2009Annual Report.pdf

Item 1: D An Initial (Original)
Submission
OR 00 Resubmission No:
Form 1 Approved
OMS No. 1902-0021
(Expires 12/31/2011)
Form 1-F Approved
OMS No. 1902-0029
(Expires 12/31/2011)
Form 3-0 Approved
OMS No. 1902-0205
(Expires 1/31/2012)
THIS FILING IS
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FERC FINANCIAL REPORT
FERC FORM No.1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)
Avista Corporation
Year/Period of Report
End of 2009/04
FERC FORM No.1/3-Q (REV. 02-04)
..
IDENTIFICATION
01 Exact Legal Name of Respondent 02 YearlPeriod of Report
Avista Corporation End of 2009/04
03 Previous Name and Date of Change (if name changed during year)
1 1
04 Address of Principal Offce at End of Period (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
05 Name of Contact Person 06 Title of Contact Person
Christy Burmeister-Smith VP and Controller
07 Address of Contact Person (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
08 Telephone of Contact Person,/nc/uding 09 This Report Is 10 Date of Report
Area Code (1) D An Original (2) IX A Resubmission (Mo,Da, Yr)
[phone] 05/12/2010
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned offcer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
"
01 Name 03S'LtIi /04 Date Signed
Christy Burmeister-Smith --(Mo,Da, Yr)
02 Title
VP and Controller ¡tristÝ BurmeisIer-Smith 05/12/2010
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and wilingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/1612010
LIST OF SCHEDULES (Electric Utiit)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
1 General Information 101
2 Control Over Respondent 102 NIA
3 Corporations Controlled by Respondent 103
4 Offcers 104
5 Directors 105
6 Information on Formula Rates 106(a)(b)
7 Important Changes During the Year 108-109
8 Comparative Balance Sheet 110-113
9 Statement of Income for the Year 114-117
10 Statement of Retained Earnings for the Year 118-119
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)
14 Summary of Utilit Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 N/A
16 Electric Plant in Service 204-207
17 Electric Plant Leased to Others 213 N/A
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utilty Plant 219
21 Investment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab)N/A
24 Extraordinary Propert Losses 230 NIA
25 Unrecovered Plant and Regulatory Study Costs 230 NIA
26 Transmission Service and Generation Interconnection Study Costs 231
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred Income Taxes 234
30 Capital Stock 250-251
31 Other Paid-in Capital 253
32 Capital Stock Expense 254
33 Long-Term Debt 256-257
34 Reconcilation of Reported Net Income with Taxable Inc for Fed Inc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Deferred Investment Tax Credits 266-267
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/1612010
LI T OF SCHEDULES (Electric Utilty) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Acclerated Amortization Propert 272-273 NIA
39 Accumulated Deferred Income Taxes-Other Propert 274-275
40 Accumulated Deferred Income Taxes-Other 276-277
41 Other Regulatory Liabilties 278
42 Electric Operating Revenues 300-301
43 Sales of Electricity by Rate Schedules 304
44 Sales for Resale 310-311
45 Electric Operation and Maintenance Expenses 320-323
46 Purchased Power 326-327
47 Transmission of Electricity for Others 328-330
48 Transmission of Electricity by ISOIRTOs 331 NIA
49 Transmission of Electricity by Others 332
50 Miscellaneous General Expenses-Electric 335
51 Depreciation and Amortization of Electric Plant 336.337
52 Regulatory Commission Expenses 350.351
53 Research, Development and Demonstration Activities 352-353 NIA
54 Distribution of Salaries and Wages 354-355
55 Common Utilty Plant and Expenses 356 "
56 Amounts included in ISOIRTO Settlement Statements 397 NIA
57 Purchase and Sale of Ancilary Services 398
58 Monthly Transmission System Peak Load 400
59 Monthly ISOIRTO Transmission System Peak Load 400a NIA
60 Electric Energy Account 401
61 Monthly Peaks and Output 401
62 Steam Electric Generating Plant Statistics 402-403
63 Hydroelectric Generating Plant Statistics 406-07
64 Pumped Storage Generating Plant Statistics 408-409 NIA
65 Generating Plant Statistics Pages 410-411
66 Transmission Line Statistics Pages 422-423
,
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) FiA Resubmission 04/1612010
LI T OF SCHEDULES (Electric Utilty) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule Reference
Page No.
(b)
424-425
426-427
429
450
Remarks
(a)
67 Transmission Lines Added During the Year
68 Substations
69 Transactions with Associated (Affliated) Companies
70 Footnote Data
Stockholders' Reports Check appropriate box:
i! Two copies wil be submitted
o No annual report to stockholders is prepared
(c)
NIA
FERC FORM NO.1 (ED. 12-96)Page 4
Name of Respondent
Avista Corporation
This Report Is:
(1) 00 An Original
(2) D A Resubmission
Date of Report
(Mo,Da, Yr)
04/1612010
YearlPeriod of Report
End of 2009/04
GENERAL INFORMATION
1. Provide name and title of offcer having custody of the general corporate books of account and address of
offce where the general corporate books are kept, and address of offce where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
C. Burmister-Smth, Vioe President, Controller, and Prinoipal Aooouting Offioer
1411 E. Mission Avenue
Spokae, WA 99207
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
State of Washington, Xnoorporated Maroh 15, 1889
3. If at any time during the year the propert of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not Aplioable
4. State the classes or utilty and other services furnished by respondent during the year in each State in which
the respondent operated.
Eleotrio servioe in the states of Washington, Xdaho and Montana
Natural gas servioe in the states of Washington, Xdaho and Orego
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous yeats certified financial statements?
(1) D Yes... Enter the date when such independent accountant was initially engaged:
(2) IX No
FERC FORM NO.1 (ED. 12-87)PAGE 101
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
C )RPORATIONS CONTROLLED BY R SPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accunts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each part.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 Avista Capital, Inc.Parent company to the 100
2 Company's subsidiaries.
3
4 Advantage 10, Inc.Provider of utilty bil 74.36 Subsidiary of
5 processing, payment and Avista Capital
6 information services to multi
7 site customers in North Amer.
8
9 Ecos 10, Inc.Formed in 2009 to acquire 100 by Advantage 10 Subsidiary of
10 Ecos Consulting, Inc.Advantage 10
11
12 Avista Development, Inc.Maintains an investment 100 Subsidiary of
13 portolio of real estate and Avista Capital
14 other investments.
15
16 Avista Energy, Inc.Inactive 100 Subsidiary of
17 Avista Capital
18
19 Avista Power, LLC Inactive 100 Affliate of
20 Avista Capital
21
22 Avista Turbine Power, Inc.Receives assignments of 100 Subsidiary of
23 purchase power agreements.Avista Capital
24
25 Avista Ventures, Inc.Inactive 100 Subsidiary of
26 Avista Capital
27
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
C )RPORA TIONS CONTROLLED BY R SPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accunts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each part holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accunts, regardless of the relative voting rights of each part.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 Pentzer Corporation Parent company of Bay Area 100 Subsidiary of
2 Manufacturing and Pentzer Avista Capital
3 Venture Holdings.
4
5 Pentzer Venture Holdings Inactive 100 Subsidiary of
6 Pentzer Corporation
7
8 Bay Area Manufacturing Holding Company 100 Subsidiary of
9 Pentzer Corporation
10
11 Advanced Manufacturing and Development, Inc.Performs custom sheet metal 82.95 Subsidiary of
12 dba Metalfx manufacturing of electronic Bay Area
13 enclosures, parts and systems Manufacturing.
14 for the computer, telecom and
15 medical industries. AM&D
16 also has a wood products
17 division.
18
19 Avista Receivables Corporation Acquires and sells accunts 100 Subsidiary of
20 receivable of Avista Corp.Avista Corp.
21
22 Spokane Energy, LLC Marketing of energy.100 Affliate of
23 Avista Corp.
24
25 Avista Capital II An affliated business trust 100 Affliate of
26 formed by the Company.Avista Corp.
27 Issued Pref. Trust Securities
FERC FORM NO.1 (ED. 12-96)Page 103.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/1612010
C :lRPORATIONS CONTROLLED BY R SPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See'the Uniform System of Accunts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each part holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each part.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1
2 Avista Northwest Resources, LLC Formed in 2009 to own 100 Subsidiary of
3 an interest in a venture Avista Capital
4 fund investment
5
6 Steam Plant Square, LLC Commercial offce and retail 90 Affliate of
7 leasing.Avista Development
8
9 Courtard Offce Center Commercial offce and retail 100 Affliate of
10 leasing.Avista Development
11
12
13
14
15
16
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18
19
20
21
22
23
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26
27
FERC FORM NO.1 (ED. 12-96)Page 103.2
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
OFFICERS
1. Report below the name, title and salary for each executive offcer whose salary is $50,000 or more. An "executive offcer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remurieration of the previous
incumbent, and the date the change in incumbency was made.
I Line litie Name of Offcer . ::alary
No.for Year
(a)(b)(c)
1 Chairman of the Board. President S. L. Morris
2 and Chief Executive Offcer
3
4 Executive Vice President (Resigned 3/31/2009)M. K. Malquist
5
6 Senior Vice President and Chief Financial Offcer M. T. Thies
7
8 Senior Vice President, General Counsel M. M. Durkin
9 and Chief Compliance Offcer
10
11 Senior Vice President and Corporate Secretary K. S. Feltes
12 with responsibilty for Human Resources
13
14 Vice President, Controller and C. M. Burmeister-Smith
15 Principal Accunting Ofcer
16
17 Vice President and Chief Information Offcer J. M. Kensok
18
19 Vice President with responsibilty for Transmission D. F. Kopczynski
20 and Distribution Operations
21
22 Vice President and Chief Counsel for Regulatory and D. J. Meyer
23 Governmental Affirs
24
25 Vice President, with responsibilty for State and K. O. Norwood
26 Federal Regulation
27
28 Vice President and Environmental Compliance Offcer D. P. Vermillon
29
30 Vice President of Finance and Treasurer A. M. Wilson
31 (Resigned 6/12/2009)
32
33 Vice President, with responsibilty for R. D. Woodworth
34 Sustainable Energy Solutions
35
36 Vice President, Finance J. R. Thackston
37 (Effctive 6/12/2009)
38
39 Treasurer D. C. Thoren
40 (Effective 6/12/2009)
41
42 Vice President, Energy Resources R. L. Storro
43 (Effctive 1/1/2009)
44
FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
DIRECTORS
1. Report below the information called for conceming each director of the respondent who held offce at any time dunng the year. Include in column (a), abbreviated
titles of the direcors who are offcers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
Lll)e Name (anÇl :ritie) of Director principai Business AddressNo.(a)(b)
1 Scott L. Morris-1411 E Mission Ave., Spokane, WA, 99202
2 (Chairman of the Board, President & CEO)
3
4 Erik J. Anderson 3720 Carilon Point, Kirkland, WA 98033
5
6 Kristianne Blake***P.O. Box 28338, Spokane, WA 99228
7
8 Brian W. Dunham 5721 SE Columbia Way, Suite 200, Vancouver, WA 986661
9
10 Roy Lewis Eiguren 702 W. Idaho St., Suite 1100, Boise, ID 83702
11
12 Jack W. Gustavel *-1260 Riverstone Dr., 3rd Floor, Coeurd Alene, ID 83814
13
14 John F. Kelly 142 Isla Dorada Blvd., Coral Gables, FL 33143
15
16 Michael L. Noel 11960 W. Six Shooter Rd. , Prescott, AZ 86305
17
18 Heidi B. Stanley P.O. Box 8650, Spokane, WA 99203
19
20 R. John Taylor-*111 Main Street, Lewiston ID 83501
21
22 Marc F. Racicot 28013 Swan Cove Dr., Big Fork, MT 59911
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FERC FORM NO.1 (ED. 12-95)Page 105
"
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) Fi A Resubmission 0411612010
INFORMATION ON FORMULA RATES
FERC Rate SchedulelTariff Number FERC Proceeding
Does the respondent have formula rates?DYes
i: No
1. Please list the Commission accpted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accpting the rate(s) or changes in the accpted rate.
I Line
No.FERC Rate Schedule or Tariff Number FERC Proceeding
1 The Company has no formula rates.
2
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FERC FORM NO.1 (NEW. 12-oS)Page 106
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) n A Resubmission 04/16/2010
INFORMATION ON FORMULA RATES
FERC Rate SchedulelTariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)DYesfilings containing the inputs to the formula rate(s)?
ix No
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
Formula Rate FERC RateLineDocument Date Schedule Number or
No.Accession No.\ Filed Date Docket No.Description Tariff Number
1 No formula rates
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FERC FORM NO.1 (NEW. 12-08)Page 106a
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) n A Resubmission 04/1612010
INFORMATION ON FORMULA RATES
Formula Rate Variances
1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or billng) was derived if different frm the reported amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
4. Where the Commission has provided guidance on formula rate inputs, the specifc proceeding should be noted in the footnote.
Line
No.Page No(s).Schedule Column Line No
1 No formula rates
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FERC FORM NO.1 (NEW. 12-oS)Page 106b
Name of Respondent
Avista Corporation
Date of Report Year/Period of Report
End of 2009/Q4
This Report Is:
(1) (! An Original
(2) 0 A Resubmission
1M ORTANT CHANGES DURING THE QUARTERIEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the propert, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees inCluding issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an offcer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
part or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockh,olders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in offcers, directors, major security holders and voting powers of the respondent that may have
occrred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
04/16/2010
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 041612010 2009/04
IMPORTANT CHAGES DURING THE OUARTERNEAR (Continued)
1. None2. None
3. None4. None5. None
6. Avista Receivables Corporation (ARC) is a wholly owned, bankrptcy-remote subsidiar of Avista Corp.
formed for the purose of acquiring or purchasing interests in certin acounts receivable, both biled and unbiled, of the
Company. Avista Corp., ARC and a third-par financial institution ar paries to a Receivables Purchase Agreement,
and on March 13, 2009 that agreement was amended to, among other things, extnd the termination date to March 12,
2010. Under the Receivables Purchase Agreement, ARC ca sell without recurse, and such financial institution wil
purchase, on a revolving basis, up to $85.0 millon of those receivables. ARC is obligated to pay fees that approximate
the purchasets cost of issuing commercial paper equal in value to the interests in receivables sold. The amount of such
fees is included in other operating expenses of Avist Corp. The Receivables Purchase Agreement has financial
covenants, which are substatially the same as those of A vista Corp.' s committed lines of credit. Based on calculations
of eligible receivables, ARC had the abilty to sell up to $85.0 milion of receivables under this revolving agreement at
each of December 31, 2009 and December 31,2008. There were not any accounts receivable sold under this revolving
agreement as of December 31,2009 and $17.0 milion were sold as of December 31,2008.
The Company has a committed line of credit agreement with varous bans in the tota amount of $320.0 milion
with an expiration date of AprilS, 2011. Under the credit ageement, the Company can borrow or request the issuance of
lettrs of credit in any combination up to $320.0 milion. The Company had $87.0 millon in borrowings outstading
under this committed line of credit as of December 31,2009 and $250.0 milion as of December 31,2008. Total letters
of credit outstading were $28.4 milion as of December 31, 2009 and $24.3 millon as of December 31, 2008. The
committed line of credit is secured by $320.0 milion of non-transferable First Mortgage Bonds of the Company issued to
the agent ban that would only become due and payable in the event, and then only to the extent, that the Company
defaults on its obligations under the committed line of credit.
Additionally, the Company has a committed line of credit agreement with various banks in the total amount of
$75.0 milion with an expiration date of AprilS, 2011 (entered in November 2009). The Compnay did not have any
borrowings outstading under this agreement at December 31, 2009. A vista Corp. may elect to increase the committed
line of credit by up to $25.0 milion under the same agreement. The committed line of credit is secured by $75.0 milion
of non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due and
payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of
credit. This credit agreement was approved by the respective regulatoiy commissions as follows: WUTC (Docket No.
UE-081842); IPUC (Case No. AVU-U-08-02 Order No. 30673); and OPUC (DocketUF 4260).
On September 22, 2009, the Company issued $250.0 milion of 5.125 percent First Mortgage Bonds due in 2022.
The net proceeds from the issuance of $249.4 milion (net of discounts and before Avista Corp.'s expenses) were used to
retire variable rate short-term borrowings outsding under our $320.0 millon committed line of credit, and for general
corporate purposes. This debt issuance was approved by the respective regulatoiy commissions as follows: WUC
(Docket No. UE-081842 Order No.2); IPUC (Cae No. A VU-U-08-01 Order No. 30670); and OPUC (Docket UF
4246(1) Order No. 08-542).
In 2004, the Company issued Junior Subordinated Debt Securities, with a principal amount of$61.9 milion to
AVA Capita Trut m, an affliated business trst formed by the Company. Concurently, AVA Capita Trust il issued
$60.0 milion of Preferred Trust Securties to third paries and $1.9 milion of Common Trust Securities to the Company.
On April 1, 2009 , AVA Capita Trust il redeemed all of the Preferred Trust Securities issued to third paries with a
principal balance of $60.0 millon and all of the Common Trust Securties issued to the Company with a principal
balance of $1.9 milion. Concurrently, the Company redeemed the total amount outstanding of its Junior Subordinated
Debt Securities, at 100 percent of the principal amount ($61.9 milion) plus accrued interest held by A VA Capital Trust
il. The Company's net redemption of $60.0 millon was funded by borrowings under its $320.0 millon committed lineof credit agreement. .
IFERC FORM NO.1 (ED. 12-96) Page 109.1
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2010 2009/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
Reference is made to Note 22 of the Notes to Financial Statements.
None
Reserved
See page 123 of this Report.
Malyn K. Malquist, Excecutive Vice President, left the Company effective March 31, 2009.
An M. Wilson, Vice President of Finance and Treasurer, left the Company in June 2009.
On May 8, 2009, the Board of Directors of Avista Corporation elected Marc Raicot to serve as a director on the
board effective August 1,2009. Mr. Racicot wil stad for election to the board at the next anual meeting of
shareholders on May 13,2010. Mr. Racicot was appointed to serve on the Energy, Environmental & Operations and
Finance Committees of the board.
On May 18,2009, Avista Corporation named Jason Thackston as Vice President of Finance effective June 12,
In December 2008, the City of Forsyt, Montaa issued $17.0 milion of its Pollution Control Revenue
Refuding Bonds, Series 2008 (Avista Corp. Colstrp Project) due 2034 on behalf of Avista Corp. The proceeds of the
Bonâs were used to refund $17.0 milion of Pollution Control Revenue Refunding Bonds, Series 1999B (A vista Corp.
Colstip Project) issued by the City of Forsyt, Montaa on behalf of Avista Corp., which were subject to remarketing or
refuding on December 31, 2008. In December 2009, A vista Corp. purchased the Bonds and expects that at a later date,
subject to market conditions, the bonds wil be refunded or remarketed to unaffliated investors. Although Avista Corp.
is now the holder of these Pollution Control Bonds, the bonds wil not be cancelled but wil remain outsding under the
City of Forsyt's indentue. However, so long as Avista Corp. is the holder, the bonds wil not be reflected as an asset or
a liabilty on Avista Corp.'s Consolidated Balance Sheet.7. None
8. Average anua wage increases were 2.4% for non-exempt employees effective March 2,2009. Average
anual wage increases were 2.8% for exempt employees effective March 2, 2009. There were no wage increases for
offcers. Cert bargaining unit employees received increases ranging from 2.0% to 4.0% effective in March and April
2009.
9.
10.
11.
12.
13.
2009.
On May 18,2009, Avista Corporation named Diane Thoren as Treasurer effective June 12,2009.
14. Proprieta capital is not less than 30 percent.
IFERC FORM NO.1 (ED. 12-96) Page 109.2
Name of Respondent This Report Is:Date of Report Year/Period of Report
Avista Corporation (1 )~An Original (Mo,Da, Yr)
(2)D A Resubmission 04/1612010 End of 2009/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
1 UTILITY PLANT
2 Utilty Plant(101-106, 114)200-201 3,546,192,091 3,340,068,198
3 Construction Work in Progress (107)200-201 57,217,478 75,568,224
4 TOTAL Utilty Plant (Enter Total of lines 2 and 3)3,603,409,569 3,415,636,422
5 (Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111, 115)200-201 1,219,877,922 1,142,578,137
6 Net Utilty Plant (Enter Total of line 4 less 5)2,383,531,647 2,273,058,285
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)202-203 0 0
8 Nuclear Fuel Materials and Assemblies-Stock Accunt (120.2)0 0
9 Nuclear Fuel Assemblies in Reactor (120.3)0 0
10 Spent Nuclear Fuel (120.4)0 0
11 Nuclear Fuel Under Capital Leases (120.6)0 0
12 (Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.5)202-203 0 0
13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12)0 0
14 Net Utilty Plant (Enter Total of lines 6 and 13)2,383,531,647 2,273,058,285
15 Utilty Plant Adjustments (116)0 0
16 Gas Stored Underground - Noncurrent (117)C 0
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutilit Propert (121)5,031,620 4,991,551
19 (Less) Accum. Provo for Depr. and Amort. (122)897,684 890,639
20 Investments in Associated Companies (123)12,047,000 13,903,000
21 Investment in Subsidiary Companies (123.1)224-225 81,243,235 77,487,962
22 (For Cost of Account 123.1, See Footnote Page 224, line 42)
23 Noncurrent Portion of Allowances 228-229 0 0
24 Other Investments (124)23,798,439 26,240,546
25 Sinking Funds (125)0 0
26 Depreciation Fund (126)0 0
27 Amortization Fund - Federal (127)0 0
28 Other Special Funds (128)11,558,301 10,234,544
29 Special Funds (Non Major Only) (129)0 0
30 Long-Term Portion of Derivative Assets (175)45,482,748 49,312,596
31 Long-Term Portion of Derivative Assets - Hedges (176)0 0
32 TOTAL Other Propert and Investments (Lines 18-21 and 23-31)178,263,663 181,279,560
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only) (130)0 0
35 Cash (131)2,462,480 1,674,372
36 Special Deposits (132-134)1,630,32~1,600,000
37 Working Fund (135)848,613 619,853
38 Temporary Cash Investments (136)652,010 2,684,444
39 Notes Receivable (141)629,625 63,451
40 Customer Accunts Receivable (142)188,271,550 207,867,900
41 Other Accounts Receivable (143)6,484,963 6,188,617
42 (Less) Accum. Provo for Uncollectible Acc.-Credit (144)3,710,770 5,844,603
43 Notes Receivable from Associated Companies (145)0 0
44 Accounts Receivable from Assoc. Companies (146)101,231 120,021
45 Fuel Stock (151)227 4,294,013 3,673,039
46 Fuel Stock Expenses Undistributed (152)227 0 0
47 Residuals (Elec) and Extracted Products (153)227 0 0
48 Plant Materials and Operating Supplies (154)227 18,386,509 17,455,835
49 Merchandise (155)227 0 0
50 Other Materials and Supplies (156)227 0 0
51 Nuclear Materials Held for Sale (157)202-203/227 0 0
52 Allowances (158.1 and 158.2)228-229 0 0
FERC FORM NO.1 (REV. 12-03) Page 110
Name of Respondent This Report Is:Date of Report Year/Period of Report
Avista Corporation (1 )iz An Original (Mo,Da, Yr)
(2)D A Resubmission 04/16/2010 End of 2009104
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 Stores Expense Undistributed (163)227 12,83~0
55 Gas Stored Underground - Current (164.1)12,706,76 30,720,371
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)0 0
57 Prepayments (165)9,985,76C 8,415,670
58 Advances for Gas (166-167)0 0
59 Interest and Dividends Receivable (171)197,04C 10,934
60 Rents Receivable (172)553,237 646,271
61 Accrued Utilty Revenues (173)0 0
62 Miscellaneous Current and Accrued Assets (174)454,4H 194,919
63 Derivative Instrument Assets (175)53,240,001 60,546,323
64 (Less) Long-Term Portion of Derivative Instrument Assets (175)45,482,748 49,312,596
65 Derivative Instrument Assets - Hedges (176)0 874,944
66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66)251,717,85C 288,199,765
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181)15,732,877 15,852,599
70 Extraordinary Propert Losses (182.1)230a 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2)230b 0 0
72 Other Regulatory Assets (182.3)232 352,616,516 455,580,547
73 Prelim. Survey and Investigation Charges (Electric) (183)3,346,45.3,088,816
74 Preliminary Natural Gas Survey and Investigation Charges 183.1)C 0
75 Other Preliminary Survey and Investigation Charges (183.2)0 0
76 Clearing Accounts (184)0 0
77 Temporary Facilities (185)0 0
78 Miscellaneous Deferred Debits (186)233 26,105,541 32,008,980
79 Def. Losses from Disposition of Utiity Pit. (187)0 0
80 Research, Devel. and Demonstration Expend. (188)352-353 0 0
81 Unamortized Loss on Reaquired Debt (189)15,196,14f 17,151,84
82 Accumulated Deferred Income Taxes (190)234 91,975,54)131,055,525
83 Unrecovered Purchased Gas Costs (191)-39,952,004 -18,646,016
84 Total Deferred Debits (lines 69 through 83)465,021,08C 636,092,295
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84)3,278,534,240 3,378,629,905
FERC FORM NO.1 (REV. 12-03)Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
Avista Corporation (1 )IX An Original (rna, da, yr)
(2)D A Resubmission 04/1612010 end of 2009/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Currnt Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250-251 759,057,747 755,903,119
3 Preferred Stock Issued (204)250-251 0 0
4 Capital Stock Subscribed (202, 205)0 0
5 Stock Liabilit for Conversion (203, 206)0 0
6 Premium on Capital Stock (207)0 0
7 Other Paid-In Capital (208-211)253 17,498,634 19,170,532
8 Installments Received on Capital Stock (212)252 0 0
9 (Less) Discount on Capital Stock (213)254 0 0
10 (Less) Capital Stock Expense (214)254b -2,090,961 87,394
11 Retained Earnings (215, 215.1, 216)118-119 295,862,243 253,478,332
12 Unappropriated Undistributed Subsidiary Earnings (216.1)118-119 -20,871,863 -25,488,897
13 (Less) Reaquired Capital Stock (217)250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (218)0 0
15 Accumulated Other Comprehensive Income (219)122(a)(b)-2,350,286 -6,092,318
16 Total Proprietary Capital (lines 2 through 15)1,051,287,436 996,883,374
17 LONG-TERM DEBT
18 Bonds (221)256-257 1,070,256,423 824,970,979
19 (Less) Reaquired Bonds (222)256-257 0 0
20 Advances from Associated Companies (223)256-257 51,547,000 114,603,000
21 Other Long-Term Debt (224)256-257 0 0
22 Unamortized Premium on Long-Term Debt (225)230,967 239,850
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)2,167,570 1,752,256
24 Total Long-Term Debt (lines 18 through 23)1,119,866,820 938,061,573
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)0 0
27 Accumulated Provision for Propert Insurance (228.1)0 0
28 Accumulated Provision for Injuries and Damages (228.2)1,650,500 1,579,821
29 Accumulated Provision for Pensions and Benefis (228.3)123,281,094 184,587,850
30 Accumulated Miscellaneous Operating Provisions (228.4)2,916,673 2,936,173
31 Accumulated Provision for Rate Refunds (229)0 0
32 Long-Term Portion of Derivative Instrument Liabilties 2,871,25~7,140,857
33 Long-Term Portion of Derivative Instrument Liabilties - Hedges 0 0
34 Asset Retirement Obligations (230)3,971,45~4,208,327
35 Total Other Noncurrent Liabilties (lines 26 through 34)134,690,975 200,453,028
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)87,000,000 250,000,000
38 Accounts Payable (232)114,930,11C 153,032,408
39 Notes Payable to Associated Companies (233)6,882,241 2,854,178
40 Accounts Payable to Associated Companies (234)724,582 737,710
41 Customer Deposits (235)8,140,853 6,979,171
42 Taxes Accrued (236)262-263 2,222,621 6,105,577
43 Interest Accrued (237)13,476,434 10,871,471
44 Dividends Declared (238)0 0
45 Matured Long-Term Debt (239)0 0
FERC FORM NO.1 (rev. 12-03)Page 112
Name of Respondent This Report is:Date of Report YearlPeriod of Report
Avista Corporation (1 )!X An Original (mo, da, yr)
(2)D A Resubmission 04/16/2010 end of 2009104
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT($ntinued)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)0 0
47 Tax Collections Payable (241)147,57~0
48 Miscellaneous Current and Accrued Liabilties (242)55,461,901 32,188,393
49 Obligations Under Capital Leases-Current (243)0 75,206
50 Derivative Instrument Liabilties (244)18,958,058 78,603,554
51 (Less) Long-Term Portion of Derivative Instrument Liabilties 2,871,255 7,140,857
52 Derivative Instrument Liabilties - Hedges (245)50,091 0
53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 0 0
54 Total Current and Accrued Liabilties (lines 37 through 53)305,123,222 534,306,811
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)1,280,331 1,263,086
57 Accumulated Deferred Investment Tax Credits (255)266-267 5,632,508 373,728
58 Deferred Gains from Disposition of Utilty Plant (256)0 0
59 Other Deferred Credits (253)269 22,330,79~24,985,882
60 Other Regulatory Liabilties (254)278 61,709,91~55,429,522
61 Unamortized Gain on Reaquired Debt (257)2,957,42E 3,237,373
62 Accum. Deferred Income Taxes-Accel. Amort.(281)272-277 0 0
63 Accum. Deferred Income Taxes-Other Propert (282)348,074,981 334,892,041
64 Accum. Deferred Income Taxes-Other (283)225,579,82~288,743,487
65 Total Deferred Credits (lines 56 through 64)667,565,787 708,925,119
66 TOTAL LIABILITIES AND STOCKHOLDER EOUITY (lines 16, 24, 35, 54 and 65)3,278,534,24C 3,378,629,905
FERC FORM NO.1 (rev. 12-03) Page 113
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
STATEMENT OF INCOME
Ouarterly
1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
3. Report in column (g) the quarter to date amounts for electric utilty function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utilit function for the current year quarter.
4. Report in column (h) the quarter to date amounts for electric utilty function; in column 0) the quarter to date amounts for gas utilty, and in column (I)
the quarter to date amounts for other utilit function for the prior year quarter.
5. If additional columns are needed, place them in a footnote.
Annual or Ouarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utilty Plant Leased to Others. in another utiit columnin a similar manner to
a utiit department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in accunt 414, Other Utilty Operating Income, in the same manner as accounts 412 and 413 above.
Line Total Total Current 3 Months Pnor 3 Months
No.Current Year to PnorYearto Ended Ended
(Ref.)Date Balance for Date Balance for Quarterl Only Quarterl Only
Title of Accunt Page No.QuarterNear QuartrNear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(n
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 1,516,973,753 1,657,671,994
3 Operating Expenses
4 Operation Expenses (401)320-323 1,100,224,196 1,278,636,823
5 Maintenance Expenses (402)320-323 50,846,769 47,636,921
6 Depreciation Expense (403)336.337 87,089,835 82,388,834
7 Depreciation Expense for Asset Retirement Costs (403.1)336337
8 Amort. & Depl. of Utilty Plant (404-405)336.337 9,143,602 7,905,829
9 Amort. of Utility Plant Acq. Adj. (406)336-337 99,047 99,047
10 Amort. Propert Losses, Unrev Plant and Regulatory Study Cost (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debit (407.3)3,718,504 382,274
13 (Less) Regulatory Creit (407.4)10,397,806 8,388,441
14 Taxes Oter Than Income Taxes (408.1)262-263 76,582,590 72,057,352
15 Income Taxes - Federal (409.1)262-263 30,223,259 3,249,258
16 - Oter (409.1)262-263 2,111,405 53,201
17 Provision for Deferrd Income Taxes (410.1)234,272-m 23,050,105 42,600,284
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1)234, 272-277 6,214,995 4,970,670
19 InvestmentTax Creit Adj. - Net (411.4)266 -93,914 -49,308
20 (Less) Gains frm Disp. of Utilit Plant (411.6)
21 Losses frm Disp. of Utilit Plant (411.7)
22 (Less) Gains from Dispositon of Allowance (411.8)
23 Losses from Dispoiton of Allowances (411.9)
24 Accreion Expense (411.10)
25 TOTAL Utilit Operating Expenses (Enter Total of lines 4 thru 24)1,366,382,597 1,521,601,404
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 150,591,156 136,070,590
FERC FORM NO. 1/3-0 (REV. 02-04)Page 114
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2010
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any accunt thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utilty's customers or which may result in material refund to the utiit with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effcts together with an explanation of the major factors which affect the rights
of the utilty to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accunts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accunting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15. If the columns are insuffcient for reporting additional utilty departments, supply the appropriate accunt tiles report the information in a footnote to
this schedule.
ELECTRIC UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)~) ~)
GAS UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(i) (j)
OTHER UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(k) (I)Line
No.
826,294,570
124,734,689
811,918,216
109,467,920
540,088,027
25,856,467
709,683,188
26,602,670
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
621,221,944 624,698,493 479,002,252 653,938,330
42,044,915 40,308,817 8,801,854 7,328,104
71,109,022 67,721,188 15,980,813 14,667,646
7,467,875 6,448,003 1,675,727 1,457,826
99,047 99,047
947,939 153,132 2,770,565 229,142
7,405,420 6,730,732 2,992,386 1,657,709
51,664,659 47,356,209 24,917,931 24,701,143
23,099,627 143,777 7,123,632 3,105,481
1,263,060 -192,188 848,345 245,389
20,060,696 36,623,690 2,989,409 5,976,594
5,234,188 4,711,220 980,807 259,450
-44,606 -49,308 -49,308
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
STA EMENT OF INCOME FOR THE YEAR (continued)
Line TOTAL Currnt 3 Months Pnor 3 Months
No.Ended Ended
(Ref.)Quartrl Only Quartrl Only
Title of Accunt Page No.Current Year Previous Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(f)
27 Net Utilit Operating Income (Carred forward from page 114)150,591,156 136,070,590
28 Oter Income and Deductons
29 Otiíer Income
30 Nonutilt Operating Income
31 Revenue From Mercandising, Jobbing and Contrct Work (415)
32 (Less) Costs and Exp. of Merchandising, Job. & Contrct Work (416)
33 Revenues From Nonutilit Operations (417)
34 (Less) Expense of Nonutilit Operations (417.1)5,249,706 3,869,058
35 Nonoperating Rental Income (418)-3,024 7,726
36 Equit in Earnings of Subsidiary Companie (418.1)119 827,451 4,123,038
37 Interest and Dividend Income (419)5,906,409 10,085,671
38 Allowance for Oter Funds Used During Constrcton (419.1)3,078,244 5,692,491
39 Miscellaneous Nonoperating Income (421)16,000
40 Gain on Dispositon of Propert (421.1)54,105 810,694
41 TOTAL Oter Income (Enter Total of lines 31 thru 40)4,613,479 16,866,562
42 Other Income Deductons
43 Loss on Dispoiton of Propert (421.2)-2,050
44 Miscellaneous Amortion (425)1,110,572 1,110,571
45 Donations (426.1)1,405,009 956,059
46 Life Insurance (426.2)1,336,173 2,100,235
47 Penaltes (426.3)-19,900 138,152
48 Exp. for Certin Civic, Politcal & Related Activities (426.4)1,347,809 1,211,097
49 Other Deductons (426.5)1,686,420 -1,891,457
50 TOTAL Oter Income Deductons (Total of lines 43 thru 49)6,864,033 3,624,657
51 Taxes Applic. to Other Income and Deductons
52 Taxes Oter Than Income Taxes (408.2)262-263 -8,841 547,911
53 Income Taxes-Federal (409.2)262-263 -985,412 2,415,034
54 Income Taxes-Oer (409.2)262-263 -269,492 -288,122
55 Provision for Deferr Inc. Taxes (410.2)234, 272-277 -223,696 1,523,886
56 (Less) Provisio for Deferred Income Taxes-Cr. (411.2)234, 272-27 3,386,934 3,294,942
57 Investmnt Tax Creit Adj.-Net (411.5)
58 (Less) Investment Tax Creit (420)
59 TOTAL Taxes on otr Incme and Deuctons (Total of lines 52-58)-4,874,375 903,767
60 Net Other Income and Deducons (Total of lines 41,50,59)2.623,821 12,338,138
61 Interest Charges
62 Interest on Long-Tenn Debt (427)55,36,849 62,954,659
63 Amort. of Debt Disc. and Expense (428)2,109,201 922,381
64 Amortzation of Loss on Reaquire Debt (428.1)3,572,357 3,759,437
65 (Less) Amort of Premium on Debt-Credit (429)8,883 8,885
66 (Less) Amortzation of Gain on Reaquired Debt-Credit (429.1)
67 Interet on Debt to Asoc. Companies (430)2,144,504 6,218,511
68 Oter Interest Expense (431)3,434,267 5,554,756
69 (Les) Allowance for Borrowed Funds Used During Constrcton-Cr. (432)544,568 4,611,851
70 Net Interet Charges (Total of lines 62 thru 69)66,143,727 74,789,008
71 Income Before Extrordinary Items (Total of lines 27, 60 and 70)87,071,250 73,619,720
72 Extaordinary Items
73 Extaordinary Income (434)
74 (Less) Extordinary Deductons (435)
75 Net Extrordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Oter (409.3)262-263
77 Extordinary Items Aft Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77)87,071,250 73,619,720
FERC FORM NO. 1/3-0 (REV. 02-04)Page 117
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612010
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary eamings for the year.
3. Each credit and debit during the year should be identified as to the retained eamings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary accunt affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first accunt 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line ItemNo. (a)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Accunt 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acc. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acc. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acc. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acc. 437)
30 Dividends Declared-Common Stock (Account 438)
31
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)
37 Transfers from Acc 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1,9,15, 16,22,29,36,37)
Contra Primary
ccount Affected
(b)
Current
QuarterlYear
Year to Date
Balance
(c)
Previous
OuarterlYear
Year to Date
Balance
(d)
1---- --~-
- - I --- - -- - - - -,,---- ---- - -I --- - -- - --- --" ---
- ---- ¡-- --- --- -- -86,243,799
796,180)
796,180)
69,496,682
- - - - I -- " - --- - -
-4,360,374 ( 37,070,823)
-44,360,374
500,486
294,314,122
37,070,823)
535,087
251,930,211
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2010
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings accunt in which recorded (Accunts 433, 436
- 439 inclusive). Show the contra primary accunt affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained eamings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line ItemNo. (a)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Accunt 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acc. 215.1)
47 TOTAL Approp. Retained Eamings (Acc. 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acc. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Accunt
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Accunt 418.1)
51 (Less) Dividends Received (Debit)
52 Equity transactions of subsidiaries
53 Balance-End of Year (Total lines 49 thru 52)
Current
OuarterlYear
Year to Date
Balance
Previous
OuarterlYear
Year to Date
Balance
1,548,121 1,548,121
1,548,121 1,548,121" -- - -----1 --
1,548,121
295,862,243
1,548,121
253,478,332" - -I - -" -------r- - --- --,,-----
-25,488,897
827,451
14,672,673)
4,123,038
3,789,583
-20,871,863
14,939,262)
25,88,897)
FERC FORM NO. 1/3.0 (REV. 02-04)Page 119
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identfy separately such items as
investments, fied asset, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Al provide a reconciliation betwn "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Actvities - Other: Include gains and losses pertining to operating actities only. Gains and losses pertining to investing and financing activities should be reporte
in those actvities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taes paid.
(4) Investing Activities: Include at Other (line 31) net cash outfow to acquire other companies. Provide a reconcilation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line Description (See Instruction NO.1 for Explanation of Codes)Current Year to Date Previous Year to Date
No.OuarterlYear OuarterlYear
(a)(b)(c)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)87,071,250 73,619,720
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion 96,233,438 90,390,864
5 Amortization of deferred power and natural gas costs 51,358,730 45,835,653
6 Amortization of debt expense 5,672,674 4,672,935
7 Amortization of investment in exchange power 2,450,031 2,450,031
8 Deferred Income Taxes (Net)9,011,417 41,798,683
9 Investment Tax Credit Adjustment (Net)5,258,780 -49,308
10 Net (Increase) Decrease in Receivables 18,733,830 -116,961,581
11 Net (Increase) Decrease in Inventory 16,449,128 -18,855,778
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses -27,996,937 2,228,853
14 Net (Increase) Decrease in Other Regulatory Assets -10,391,960 -20,468,183
15 Net Increase (Decrease) in Other Regulatory Liabilities 1,329,752 2,372,800
16 (Less) Allowance for Other Funds Used During Construction 3,078,244 5,692,491
17 (Less) Undistributed Earnings from Subsidiary Companies 827,452 4,123,038
18 Other (provide details in footnote):338,032 601,532
19
20 Changes in other non-current assets and liabilties -20,200,944 -10,063,226
21 Net change in receivables allowance -2,133,833 2,878,927
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)229,277,692 90,636,393
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utilty Plant (less nuclear fuel)-206,916,479 -219,796,264
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utilty Plant
29 Gross Additions to Nonutilit Plant
30 (Less) Allowance for Oter Funds Used During Construction
31 Other (provide details in footnote):
32
33
34 Cash Outfows for Plant (Total of lines 26 thru 33)-206,916,479 -219,796,264
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)128,775 7,998,322
38
39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies 4,689,731 1,191,118
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent
Avista Corporation
This ~ort Is:(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04116/2010
YearlPeriod of Report
End of 2009/Q4
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fied assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a recncilation betwen "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertining to operating activities only. Gains and losses pertaining to investing and financing actvities should be reporte
in those actvities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outfow to acquire other companies. Provide a reconcilation of assets acquired with liabilties assume in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See Instruction NO.1 for Explanation of Codes)
(a)
Current Year to Date
OuarterlYear
(b)
Previous Year to Date
OuarterlYear
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (Increase) Decrease in Receivables
50 Net (Increase) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote):
54 Changes in other propert and investments
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68 Cash received for settlement of interest rate swap agreements
69
70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
77 Long-term debt and short-term borrowing issuance costs
78 Net Decrease in Short-Term Debt (c)
79 Cash paid for settlement of interest rate swap agreements
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)
87
88 Cash and Cash Equivalents at Beginning of Period
89
90 Cash and Cash Equivalents at End of period
6,013
-1,000,477 2,006,496
249,425,000 296,165,000
2,621,946 28,564,671
250,000,000
10,776,222
262,823,168 574,729,671
-78,931,206 -401,855,029
-3,726,398
-163,000,000
-5,023,987
-16,395,000
-44,360,372 -37,070,823
FERC FORM NO.1 (ED. 12-96)Page 121
Name of Respondent
Avista Corporation
Date of Report Year/Period of Report
End of 2009/Q4
This Report Is:
(1) 12 An Original
(2) 0 A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any accunt thereof. Classify the notes accrding to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Accunt 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Corm mission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes suffcient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
04/1612010
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original.(Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO FINANCIA STATEMENTS
NOTE i. SUMMARY OF SIGNIFICAN ACCOUNTING POLICIES
Nature of Business
A vista Corporation (A vista Corp. or the Company) is an energy company engaged in the generation, trmission and distrbution of
energy, as well as other energy-related businesses. Avista Corp. generates, trsmits and distrbutes electrcity in par of eastern
Washington and nortern Idaho. In addition, Avista Corp. has electrc generating facilties in Montana and nortern Oregon. Avista
Corp. also provides natual gas distrbution servce in par of eastern Washington and nortern Idaho, as well as par of norteast and
southwest Oregon. A vista Capital, Inc. (A vista Capital), a wholly owned subsidiar of A vista Corp., is the parent company of all of
the subsidiar companies including Avista Energy, Inc. (Avista Energy) and Advantage IQ, Inc. (Advantage IQ), a 74 percent owned
subsidiar as of December 3 1,2009. Avista Energy was an electrcity and natual gas marketing, trading and resource management
business. On June 30, 2007, Avista Energy completed the sale of substatially all of its contracts and ongoing operations. See Note 3
for fuer information. Advantage IQ is a provider of facilty inonntion and cost management servces for multi-site customers
thoughout Nort America.
Accounting Standards Codifcation
In June 2009, the Financial Accountig Stadads Board (FASB) issued Statement of Fincial Accounting Stadads (SFAS) No.
168, "The Accounting Stadads Codification and the Hierarchy of Generally Accepted Accounting Principles - a replacement of
FASB Statement No. 162." Ths sttement replaces all previously issued accountig stadards and establishes the FASB Accounting
Stadards Codification (ASC). The ASC is the single source of authoritative nongovernental accountig principles generally
accepted in the United States of America (U.S. GAAP) and is effective for all interi and anual periods ending after September iS,
2009. All existing accountig stadads documents were superseded. All other accountig literatue not included in the ASC is
considered nonauthoritative. The adoption of the ASC did not have any impact on the Company's fiancial condition, results of
operations and cash flows, as the ASC did not change existing U.S. GAAP. The adoption of the ASC only resulted in changes to the
Company's fiancial statement disclosure references. In order to faciltate the trsition to the ASC, the Company has elected to show
references to U.S. GAA within this report prior to the ASC along with a parenthetical ASC reference.
Basis of Reporting
The fiancial statements include the assets, liabilties, revenues and expenses of the Company and have been prepared in accordace
with the accountig requirements of the Federal Energy Regulatory Commission (FERC) as set fort in its applicable Uniform System
of Accounts and published accountig releases, which is a comprehensive basis of accounting other th U.S. GAA. As required by
the FERC, the Company accounts for its investment in majority-owned subsidiares on the equity method rather than consolidatig the
assets, liabilties, revenues, and expenses of these subsidiares, as required by U.S. GAA. The accompanyig financial statements
include the Company's proportonate share of utilty plant and related operations resultig from its interests in jointly owned plants. In
addition, under the requirements of the FERC, there are differences from U.S. GAA in the presentation of(1) curent porton of
long-term debt (2) assets and liabilties for cost of removal of assets, (3) assets held for sale, (4) regulatory assets and liabilties, (5)
deferred income taes and (6) comprehensive income.
Use of Estimates
The prepartion of the fiancial statements in conformity with U.S. GAA requires management to mae estimates and assumptions
that afect amounts reported in the fiancial statements. Significant estiates include:
· determining the market value of energy commodity derivative assets and liabilties,
· pension and other postretement benefit plan obligatons,
. contigent liabilties,
· recoverabilty of regulatory assets,
. stock-based compensation, and
. unbiled revenues.
Changes in these estates and assumptions are considered reasonably possible and may have a materal effect on the financial
statements ¡md thus actual results could differ from the amounts reportd and disclosed herein.
System of Accounts
The accountig records of the Company's utilty operations are maintained in accordance with the uniform system of accounts
IFERC FORM NO.1 (ED. 12-88)Page 123.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) A An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 04/161010 2009/04
NOTES TO FINANCIAL STATEMENTS CContinued\
prescribed by the FERC and adopted by the sta regulatory commissions in Washigton, Idao, Montaa and Oregon.
Regulation
The Company is subject to state regulation in Washingtn, Idao, Montaa and Oregon. The Company is also subject to federal
regulation by the FERC.
Operating Revenues
Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. The
determination of the energy sales to individua customers is based on the reading of their meters, which occur on a systematic basis
thoughout the month. At the end of each calendar month the amount of energy delivered to customers since the date of the last meter
readig is estimated and the corresponding unbiled revenue is estiated and recorded. Accounts receivable includes unbiled energy
revenues of$89.6 milion as of December 31, 2009 and $84.3 milion (net of$I 1.4 milion ofunbiled receivables sold) as of
December 31,2008. See Note 5 for information related to the sale of accounts receivable.
Advertising Exenses
The Company expenses advertin costs as incured. Advertsing expenses were not a material portion of the Company's operatig
expenses in 2009 and 2008.
Depreciation
For utility operations, depreciation expense is estiated by a method of depreciation accounting utilizing composite rates for utilty
plant. Such rates are designed to provide for retirements of propertes at the expirtion of their service lives. For utilty operations, the
ratio of depreciation provisions to average depreciable propert was 2.78 percent in 2009 and 2.77 percent in 2008.
The average serce lives for the following broad categories of utility plant in service are:
. electrc thermal production - 32 years,
. hydroelectrc production - 74 yea,
. electrc tranmision - 51 years,
. electric distrbution - 4 i years, and
. natual gas ditribution propert - 53 year.
Tax Other Than Income Tax
Taxes other th income taes include state excise taes, city occupational and frchise taes, real and personal propert taes and
cert other taes not based on net income. These taes are generally based on revenues or the value of propert. Utilty related taes
collected from customers (priy state excise taes and city utility taes) are recorded as operatin revenue and expense and totaed
$56.8 milion in 2009 and $53.9 millon in 2008.
AUowance lor Funds Used During Construction
The Allowance for Funds Used During Constrcton (AFDC) represents the cost of both the debt and equity fuds used to fiance
utility plant additions during the constrction period. In accordance with the unform system of accounts prescribed by regulatory
authorities, AFUDC is capitaiz as a par of the cost of utilty plant and the debt related porton is credited curently againt total
interest expense in the Statements of Income. The Company generally is permitted, under established regulatory rate practices, to
recover the capitalized AFUDC, and a fai retu thereon, though its inclusion in rate base and the provision for depreciaton after the
related utilty plant is placed in service. Cash inow related to AFUDC generally does not occur until the related utilty plant is placed
in service and included in rate base. The effective AFUDC rate was 8.22 percent in 2009 and 8.2 percent in 2008. The Company's
AFUDC rates do not exceed the maximum allowable rates as determed in accrdace with the requiements of reguatory authoriies.
Income Taxs
A deferred income ta asset or liabilty is detrmed based on the enacted ta rates that wil be in effec when the diereces betwen
the fiancial statement caring amounts and ta basis of existig asset and liabilties are expcted to be report in the Company's
consolidated income ta retu. The deferred income ta expense for the perod is equa to the net change in the deferrd income ta
asset and liabilty accounts from the beging to the end 9f the period The effect on deferred income taes of a change in ta rates is
recognizd in income in the period that includes the enactment date. Deferred income ta liabilties and reguatory assets are
established for income ta benefits flowed though to customers as prescribed by the respective reguatory commssions.
Stock-Based Compensation .
Compensation cost relatig to share-based payment tractions is recognizd in the Company's ficial statements based on the fair
IFERC FORM NO.1 (ED. 12-88) Page 123.2 I
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avist Corporation (2) A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
value of the equity or liabilty instrents issued. See Note 21 for fuer inormation.
Earnings per Commn Share Attributable to Avista Corporation
Basic earings per common share attbutable to Avista Corporation is computed by dividing net income attbutable to Avista
Corporation by the weighted average number of common shares outstading for the period. Diluted earings per common share
attbutable to A vista Corporation is calculated by dividing net income attbutable to A vista Corporation (adjusted for the effect of
potentially dilutive securities issued by subsidiares) by diluted weighted average common shaes outstading during the perod,
including common stock equivalent shares outstading using the treasur stock method, uness such shares are anti-dilutive. Common
stock equivalent shares include shares issuable upon exercise of stock options and contigent stock awards. See Note 20 for earings
per common share calculations.
Cash and Cash Equivalents
For the puroses of the Statements of Cash Flows, the Company considers all temporar investments with a matuty of thee months or
less when purchased to be cash equivalents. Cash and cash equivalents include cash deposits from counterparies.
Allowancefor Doubtful Accounts
The Company maintains an allowance for doubtfl accounts to provide for estimated and potential losses on accounts receivable. The
Company determines the allowance for utilty and other cusmer accounts receivable based on historical wrte-off as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certin individual
accounts. The following table presents the activity in the allowance for doubtful accounts durg the year ended December 31
(dollar in thousands):
Allowance as of the begining of the year
Additions expensed durg the year
Net deductions
Allowance as of the end of the year
2009
$5,845
5,160
(7,294)am
2008
$2,966
6,336
(3.457)~
Utilit Plant in Service
The cost of additions to utlity plant in service, including an allowance for fuds used durg constrction and replacements of units of
propert and improvements, is capitalized. Costs of depreciable units of propert retired plus costs of removal less salvage ar chaged
to accumulated depreciation.
Regulatory Deferred Charges and Credits
The Company prepares its fiancial statements in accordance with the provisions of SF AS No. 71, "Accountig for the Effects of
Certin Types of Regulation" (ASC 980) because:
· rates for regulated servces are established by or subject to approval by independent third-par regulators,
· the regulated rates are designed to recover the cost of providing the regulated serices, and
· in view of demand for the reguated services and the level of competition, it is reasonable to assume that rates can be charged
to and collected from customers at levels that will recover costs. .
ASC 980 requires the Company to reflect the impact of regulatory decisions in its fiancial statements. ASC 980 requires that certin
costs and/or obligations (such as incured power and natul gas costs not curently included in rates, but expected to be recovered or
refuded in the futue) are reflected as deferred charges or credits on the Balce Sheets. These costs and/or obligations are not
reflected in the Statements of Income until the period durg which matchig revenues are recognized.
If at some point in the futue the Company determines that it no longer meets the criteria for contiued application of ASC 980 for all
or a porton of its regulated operations, the Company could be:
· required to wrte off its reguatory assets, and
· precluded from the futue deferral of costs not recovered though rates at the time such costs are incured, even if the
Company expected to recover such costs in the futue.
The Company's priar regulatory assets include:
. power cost deferrls,
IFERC FORM NO.1 (ED. 12-88) Page 123.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) c An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/1612010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
. investment in exchage power,
. reguatory asset for deferred income taes,
. unamortzed debt repurchase costs,
. assets offsettg net utility energy commodity derivative liabilities (see Note 6 for fuer inormtion),
. expenditues for demand side management progrs,
. expenditues for conservation program,
. payments to the Coeur d Alene Tribe for past water storage and the licensing of the Spokae River Project,
. certin expenditues for licensing hydroelectrc generating facilties, and
. unfuded pensions and other postretiement benefits.
Regulatory liabilties include:
. utilty plant retiement costs,
. natu gas deferrls, and
. liabilties offsetting net utilty energy commodity dervative assets (see Note 6 for fuer inormtion).
Investment in Exhange Power-Net
The investment in exchange power represents the Company's previous investment in Washington Public Power Supply System Project
3 (WNP-3), a nuclear project that was tenninated prior to completion. Under a settlement agreement with the Bonnevile Power
Administration in 1985, Avista Corp. began receiving power in 1987, for a 32.5-year period, related to its investment in WN-3.
Though a settlement agreement with the Washingtn Utilties and Transporton Commission (WUTq in the Washington
jursdiction, A vista Corp. is amortzig the recoverable porton of its investment in WN-3 (recorded as investment in exchange
power) over a 32.5 year period begiing in 1987. For the Idao jursdiction, A vita Corp. fully amortd the recoverable portion of
its investment in exchane power.
Unamortizd Debt Exene
Unamortzed debt expense includes debt issuace costs that are amort over the life of the related debt.
Unamortized Loss on Reacquired Debt
For the Company's priar regulatory jurisdiction and for any debt repurchases begiing in 2007 in al jursdictions, premiums paid
to repurchase debt are amorted over the remaiing life of the origial debt that was repurchased or, ifnew debt is issued in
connection with the repurchase, these costs are amortd over the life of the new debt. In the Company's other regulatory
jurisdictions, premium paid to repurchase debt prior to 2007 are being amortized over the average remaing matuty of outstading
debt when no new debt was issued in connection with the debt repurchase. These costs are recovered though retal rates as a
component of interest expense.
NOTE 2. NEW ACCOUNTING STANARS
Effective Janua 1,2008, the Company adopted the provisions of SF AS No. 157, "Fai Value Measuremen~" (ASC 820-10) related
to its fiancial assets and liabilties and nonfancial assets and liabilties measured at fair value on a recuring basis. In Febru
2008, the F ASB issued Sta Position (FSP) No. 157-2, which deferred the effective date for certin portons of ASC 820- 1 0 related to
nonrecurg measurements of nonfcial assets and liabilties. Effective Janua 1,2009, the Company adopted those provisions of
ASC 820-10. The adoption of the provisions of ASC 820-10 that became effectve on Janua 1,2008 and 2009, did not have a
material impact on the Company's fiancial condition, results of operations and cash flows. However, the Company expanded
disclosures for fai value measurements that becae effective on Januar 1,2008. There were no additional disclosures related to the
provisions that became effective Janua 1,2009. See Note 18 for the expanded diclosures.
Effective Janua 1,2009, the Company adopted SFAS No. 141(R), "Business Combinons" (ASC 805-10) tht replaces previous
accounting gudace for business combinations and addresses the accounting for al tranactions or other events in which an entity
obtas control of one or more businesses. This statement requies the acquig entity in a business combination to recogn the
assets acquied, the liabilties assumed, and any noncontrolling interest in the traction at the acquiition date, measured at their fair
values as of tht date, with liited exceptions.
Effective Janua 1,2009, the Company adopted SFAS No. 160, ''Noncontrollig Interests in Consolidated Financial Statements - an
amendment of AR No.5 1" (ASC 810-10). Ths statement amended previous accountig guidace to establish accountig and
reportg stadards for a noncontrolling (minority) interest in a subsidiar and for the deconsolidation ofa subsidiar. This statement
clarfies that a noncontrolling interest in a subsidiar is an ownership in the consolidated entity that should be reported as equity in the
IFERC FORM NO.1 (ED. 12-88) Page 123.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) lÇ An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
consolidated fiancial sttements. The adoption of this statement had no material impact on the Company's ficial conditon and
results of operations.
Effective Janua 1,2009, the Company adopted SFAS No. 161, "Disclosures about Derivative Instnents and Hedging Activities"
(ASC 8 i 5- i 0) that requies disclosure of the fair value of derivative instnents and their gains and losses in a tabular format. The
sttement requires disclosure of derivative featues that are related to credit risk. The Company expanded disclosures for derivatives
and hedging activities. See Note 6 for the expanded disclosures.
Effective December 31,2009, the Company adopted FSP FAS 132(R)-1, "Employers' Disclosures about Postetirement Benefit Plan
Assets" (ASC 715-20) that amends FASB Statement No. 132(R) "Employers' Disclosures about Pensions and Oter Postretirement
Benefits" (ASC 715-20). This statement provides gudance on an employer's disclosures about plan assets of a defied benefit
pension or other postretirement plan. The Company has expanded disclosures for its pension and other postrtiement benefit plan
assets in Note 9.
Effective June 30, 2009, the Company adopted FSP FAS 157-4, "Determing Fair Value When the Volume and Level of Activity for
the Asset or Liabilty Have Significantly Decreased and Identifying Traactions That Are Not Orderly" (ASC 820-65-10-4) that
provides guidance for determining fair values of financial intnents for which there is no active market or when quoted prices may
represent distressed transactions. The guidance includes a reaffation of the need to use judgment in cert circumtaces and
requires expanded disclosues surounding equity and debt securties. The adoption of ths FSP did not have an impact on the
Company's fiancial condition, results of operations and cash flows.
Effective June 30, 2009, the Company adopted SF AS No. 165, "Subsequent Events" (ASC 855-10). Ths statement established
priciples and requiements for subsequent events related to: 1) the perod afer the balance sheet date durg which management of a
reporting entity shall evaluate events or tranactions that may occur for potential recogntion or disclosure in the fiancial statements;
2) the cirumtaces under which an entity shall recogne events or trsactions occurg afr the balance sheet date in its fiancial
statements; and 3) the disclosures that an entity shall mae about events or tractions tht occured after the balance sheet date. The
Company evaluated subsequent events up to Febru 26, 2010 (the date the fmancial statements were available to be issued).
In June 2009, the FASB issued SF AS No. 166, "Accounting for Trafers of Financial Assets an amendment ofFASB Statement No.
140" (ASC 860). This statement amends certin provisions of SF AS No. 140 (ASC 860) related to accounting for transfers of
fiancial assets and a trsferor's continuing involvement in transferred fiancial assets. The Company was required to adopt this
statement effective Janua 1,2010. The Company is evaluatig the impact this statement will have on its fiancial condition, results
of operations and cash flows. In paricular, the Company is evaluatig its accounts receivable sales (see Note 5) to determine whether
or not the transactions meet the criteria of sales offiancial assets. If the trsactions did not meet the criteria, the tractons would
be accounted for as secured borrowings. As of December 31, 2009, the Company had not sold any accounts receivable under the
revolvig agreement. The Company will finalize its evaluation durg the fist quaer of 20 1 0 to determine the impact of adoption, if
any, on its fiancial condition, results of operations and cash flows.
In June 2009, the FASB issued SFAS No. 167, "Amendments to FASB Interpretation No. 46(R)" (ASC 810). This statement caries
forward the scope ofFASB Interpretation No. 46(R) (ASC 810), with the addition of entities previously considered qualifying
special-purose entities, as the concept of these entities was eliminated in SFAS No. 166 (ASC 860). The amendments wil
significantly affect the overall consolidation analysis of varable interest entities (V). The amendments will require the Company to
reconsider previous conclusions relatig to the consolidation of VIs, includig whether an entity is a væ, whether the Company is
the væ's priar beneficiar, and what tye offiancial statement disclosures are required. The Company was required to adopt this
statement effective Janua 1,2010. The Company is evaluatig the impact ths sttement will have on its fiancial condition, results
of operations and cash flows. The Company will filiz its evaluation durg the fist quaer of 20 1 0 to deterine the impact of
adoption, if any, on its fiancial condition, results of operations and cash flows.
NOTE 3. DISPOSITION OF A VISTA ENERGY
On June 30, 2007, Avista Energ and Avista Energy Canada completd the sale of substtially all of their contracts and ongoing
operations to Shell Energy Nort America (U.S.), L.P. (Shell Energy), formerly known as Coral Energy Holding, L.P., as well as to
cerin other subsidiares of Shell Energy.
Certin asset of A vista Energy with a net book value of approximately $30 milion were not sold or liquidated. These primarly
include natual gas storage and deferred income ta assets. The Company expects that the natul gas storage wil ultimately be
transferred to Avista Corp., subject to futue regulatory approvaL. There is also a power purchase agreemerit, related to a 270 MW
IFERC FORM NO.1 (ED. 12-88) Page 123.5
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2010 2009/04
NOTES TO FINACIAL STATEMENTS (Continued)
natual gas-fired combined cycle combustion tubine plant located in Idao (Lancaster Plant). The Lancaster Plat is owned by an
unelated thd-par and all of the output from the plant is contrted to Avista Turbine Power, Inc. (an affliate of Avista Energy)
though 2026. The majority of the rights and obligations of the power purchae agreement were conveyed to Shell Energy though the
end of2009. The nghts and obligations of power purchase agreement were conveyed to Avista Corp. in Janua 2010.
In connection with the transaction, on June 30,2007, Avista Energy and its affliates entered into an Indemnfication Agreement with
Shell Energy and its afliates. Under the Indemnfication Agreement, A vista Energy and Shell Energy each agree to provide
indemnification of the other and the other's afliates for certin events and matters described in the purchase and sale agreement and
cert other tranaction agreements. Such events and mattrs include, but are not limted to, the refid proceedings arising out of the
western energy markets in 2000 and 2001 (see Note 22), existing litigation, ta liabilties, and matters related to natual gas storage
rights. In general, such indemnfication is not required unless and until a par's clais exceed $150,000 and is limited to an agegate
amount of$30 millon and a term of thee years (except for agreements or tranactions with terms longer than thee years). These
limitations do not apply to certin thd par claims.
Avista Energy's obligations under the Indemnification Agreement are guaranteed by Avista Capital puruat to a Guaranty dated June
30,2007. This Guaranty is limited to an aggregate amount of$30 milion plus certin fees and expenses. The Guaanty wil terminate
April 30, 2011 except for claims made prior to termation. As of Februar 26, 2010, neither par has made any claims under the
Indemnification Agreement or Guaty.
NOTE 4. ADVANTAGE IQ ACQUISITIONS
Effective July 2,2008, Advantage IQ completed the acquisition of Cadence Network, a pnvately held, Cincinati-based energy and
expense mangement company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in
Advantage IQ. The total value of the tracton was $37 milion.
The acquisition of Cadence Network was fided with the issuace of Advantage IQ common stock. Under the traction agreement,
the previous owners of Cadence Network can exercise a right to have their shares of Advantae IQ common stock redeemed dur
July 201 1 or July 2012 if Advantage IQ is not liquidated thoug either an initial public offering or sale of the business to a third par.
Their redemption nghts expire July 31, 2012. The redemption price would be determed based on the fai market value of
Advantage IQ at the tie of the redemption election as determed by certin independent pares.
On Augut 31,2009, Advantage IQ acquird substatially all of the assets and liabilties ofEcos Consultig, Inc. (Ecos), a Portland,
Oregon-based energy effciency solutions provider for $8.9 milion. Under the term of the tranaction, the assets and liabilties of
Ecos were acquired by a wholly owned subsidiar of Advantage IQ.
NOTE 5. ACCOUNTS RECEIVABLE SALE
A vista Receivables Corporation (ARC) is a wholly owned, banptcy-remote subsidiar of A vista Corp. formed for the purose of
acquiring or purchasing interests in certin accounts receivable, both biled and unbiled, of the Company. Avista Corp., ARC and a
third-par ficial intitution are pares to a Receivables Puchase Agreement, and on March 13,2009 tht agreement was amended
to, among other things, extend the termintion date to March 12,2010. Under the Receivables Purchase Agreement, ARC can sell
without recourse, and such fiancial intitution wil purhase, on a revolving basis, up to $85.0 millon of those receivables. ARC is
obligated to pay fees that approximate the purchaser's cost of issuing commercial paper equal in value to the interests in receivables
sold. The amount of such fees is included in other operating expenses of Avista Corp. The Receivables Purchase Agreement has
. fiancial covenants, which are substatially the same as those of Avist Corp. 's committed lines of credit (see Note 12). Based on
calculatons of eligible receivables, ARC had the abilty to sell up to $85.0 millon of receivables under this revolvin agreement at
each of December 31, 2009 and December 31, 2008. There were not any accounts receivable sold under th revolving agreement as
of December 31, 2009 and $17.0 millon were sold as of December 31, 2008.
NOTE 6. DERIATIVES AN RISK MAAGEMENT
Energy Commdi Derivatives
Avista Corp. is exposed to market riks relating to chages in electrcity and natual gas commodity prices and certin other fuel prices.
Market risk is, in general, the rik of fluctuation in the market price of the commodity being traded and is inuenced priarly by
supply and demand. Market risk includes the fluctuation in the maket price of associated derivative commodity intrents. Market
risk may also be influenced by market parcipants' nonperformance of their contrctul obligations and commitments, which affect
the supply of, or demand for, the commodity. Avista Corp. utilzes derivative intrents, such as forwards, futues, swaps and
IFERC FORM NO.1 (ED. 12-88) Page 123.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1)~An Original (Mo, Da, Yr)Avista Corporation (2) A Resubmission 04/16/2010 2009104
NOTES TO FINANCIAL STATEMENTS (Continued)
options in order to maage the varous risks relatin to these commodity price exposures. The Company has an energy resources risk
policy and control procedures to manage these risks. The Company's Risk Management Committee establishes the Company's energy
resources risk policy and monitors compliance. The Risk Management Committee is comprised of cert Company offcers and other
management. The Audit Committee of the Company's Board of Directors periodically reviews and discusses risk assessment and risk
management policies, including the Company's material fmancial and accounting risk exposures and the steps magement has
underten to control them.
As par of its resource procurement and management operations in the electrc business, A vista Corp. engages in an ongoing process
of resource optimiztion, which involves the economic selection from available energy resources to serve Avista Corp.'s load
obligations and the use of these resources to captue available economic value. Avista Corp. sells and purchases wholesale electric
capacity and energy and fuel as par of the process of acquirg and balancing resoures to serve its load obligations. These
transactons range from terms of one hour up to multiple years. A vista Corp. makes continuing projections of:
· electrc loads at varous points in time (raging from one hour to multiple years) based on, among other things, estimates of
customer usage and weather, historical data and contract terms, and
· resource availabilty at these points in time based on, among other things, fuel choices and fuel markets, estimates of
streamflows, availabilty of generating units, historic and forward market information, contract term, and experience.
On the basis of these projections, Avista Corp. makes purchases and sales of electrc capacity and energy and fuel to match expected
resources to expected electrc load requirements. Resource optimization involves generating plant dispatch and scheduling available
resources and also includes transactions such as:
. purhasing fuel for generation,
· when economical, sellig fuel and substitug wholesale electrc purchases, and
· . other wholesale tractions to captue the value of generation and transmission resources.
A vista Corp. ' s optimiztion process includes enterig into heding transactions to manage risks.
As par of its resource procurement and management operations in the natual gas business, Avista Corp. makes continuing projections
of its natu gas loads and assesses available natual gas resources. Forward natul gas contrcts are tyically for monthly delivery
periods. However, daily variations in natu gas demand can be significantly different than monthy demand projections. On the
basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a significant porton of its projected
natul gas requirements thoug forward market transactions and derivative intrents. These transactions may extend as much as
four natul gas operating years (November though October) into the futue. A vist Corp. also leaves a significant portion of its gas
supply requirements unedged for purchase in short-term and spot markets. Natual gas resoure optimiztion activities include:
. wholesale market sales of surlus gas supplies,
. purchases and sales of natual gas to use underulizd pipeline capacity, and
. sales of excess natual gas storage capacity.
Derivatives are recorded as either assets or liabilties on the balance sheet measured at estited fair value. In certin defied
conditions, a derivative may be specifically designated as a hedge for a parcular exposure. The accounting for derivatives depends
on the intended use of the derivatives and the resultig designation.
The WUC and the IPUC issued accounting orders authorizig Avista Corp. to offset commodity derivative assets or liabilties with a
regulatory asset or liabilty. Ths accounting treatment is intended to defer the recognition of mark- to-maket gains and losses on
energy commodity transactions until the period of settlement.. The orders provide for Avista Corp. to not recogniz the unealized gain
or loss on utility derivative commodity intrents in the Statements of Income. Realizd gains or losses are recognized in the period
of settlement, subject to approval for recovery though retal rates. Realizd gain and losses, subject to regulatory approval, result in
adjustments to retal rates though purchased gas cost adjustments, the Energy Recovery Mechanism (ERM) in Washingtn, the Power
Cost Adjustment (PCA) mechanism in Idaho, and periodic general rates cases.
Substatially all forward contracts to purchase or sell power and natul gas are recorded as assets or liabilties at market value with an
offsettg regulatory asset or liabilty. Contracts that are not considered derivatives under ASC 815 are generally accounted for on the
accrual basis until they are setted or realized, unless there is a decline in the fair value of the contrct that is determined to be other
than tempora.
The following table presents the underlying energy commodity derivative volumes as of December 3 t, 2009 that are expected to settle
IFERC FORM NO.1 (ED. 12-88) Page 123.7 I
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/16/2010 2009104
NOTES TO FINANCIAL STATEMENTS (Continued)
Year
2010
2011
2012
2013
2014
Thereafter
in each respective year (in thousands ofMW and mmTUs):
Puchases
Electrc Derivatives Gas Derivatives
Physical Financial Physical Financial
MWH MWH mmTUs mmTUs760 568 26,699 1,210
401 138 10,477366 4,128368 1,575
366
1,694
Sales
Electrc Derivatives
Physical FincialMWH MWH
1,381 49286 31
287
286
286
1,303
Gas Derivatives
Physical Fincial
mmTUs mmTUs
5,051
467
Foreign Currency Exhange Contracts
A signficant porton of Avist Corp.'s natual gas supply (including fuel for power generation) is obtained from Canadian sources.
Most of those tranactions are executed in U.S. dollars, which avoids foreign curency risk. A portion of Avista Corp.'s short-tenn
natual gas transactions and long-tenn Canadian tranporttion contracts are commtted based on Canadian curency prices and settled
within sixty days with U.S. dollar. In early 2009, Avista Corp. implemented a process to economically hedge a porton of the foreign
curency risk by purchasing Canadia curency when such commodity tranactions are initiated. This risk has not had a material effect
on the Company's fiancial condition, results of operations or cash flows and these differences in cost related to curency fluctutions
were included with natu gas supply costs for ratemaking. As of December 3 1,2009, the Company had a curent derivative liabilty
for foreign curency hedges ofless than $0.1 millon. As of December 3 1,2009, the Company had entered into 24 Candian curency
forward contracts with a notional amount of$10.2 milion ($10.6 millon Canan).
Interest Rate Swap Agreements
A vita Corp. enters into forward-staing interest rate swap agreements to mange the risk associated with changes in interest rates and
the impac on futue interest payments. These interest rate swap agreements relate to the interest payments for anticipated debt
issuaces. These interest rate swap agreements are considered economic hedges agait fluctuations in futue cash flows associated
with chages in interest rates. In September 2009, the Company cash settled interest rate swap contracts (notional amount of $200.0
milion) and received a tota of $ I 0.8 millon. The inteest rate swap contracts were settled concurently with the issuance of $250.0
milion of First Mortgage Bonds (see Note 13). These settlements of the interest rate swaps were deferred as a regulatory liabilty
(included as par oflong-tenn debt) and wil be amort as a component of interest expense over the life of the associated debt issued
in accordace with reguatory accounting pratices. The Company did not have any interest rate swap contracts outstading as of
December 3 1,2009.
Derivative Instruments Summry
The following table presents the fair values and locations of derivative instrents recorded on the Balance Sheet as of December 3 I,
2009 (in thousands):
Fai Value
Net Asset
Derivative Balance Sheet Location Asset Liabilty (Liabilty
Foreign curency contracts Derivative instrent liabilties
hedges $$(50)$(50)
Commodity contrct Derivative instent assets
curent 8,976 (1,219)7,757
Commodity contrcts Long-tenn derivative intrent
assets 53,765 (8,282)45,483
Commodity contracts Derivative instrent liabilties
curent 5,783 (21,870)(16,087)
Commodity contracts Long-tenn derivative intrent
liabilties ~(3,521)(2.871)
Total derivative intrents recorded on the balance sheet $69,174 $(34942)$34,232
Exosure to Demantb for Collateral
The Company's derivative contrcts often require collateral (in the fonn of cash or letters of credit) or other credit enhcements, or
IFERC FORM NO.1 (ED. 12-88) Page 123.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)Avista Corporation (2) A Resubmission 04/16/2010 2009/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
reductions or termations of a porton of the contrct though cash settlement, in the event of a downgrde in the Company's credit
ratigs or adverse changes in maret pnces. In penods ofpnce volatilty, the level of exposure can chage signficantly. As a result,
sudden and significant demands may be made against the Company's credit facilties and cash. The Company actively monitors the
exposur to possible collateral calls and taes steps to minimize capital requirements.
Certin of the Company's denvative instrents contain provisions that require the Company to maintain an investment grde credit
ratig from the major credit rating agencies. If the Company's credit ratings were to fall below investment grade, it would be in
violation of these provisions, and the counterparies to the derivative instents could request imediate payment or demand
imediate and ongoing collateraliztion on derivative instents in net liabilty positions. The aggregate fair value of all derivative
instrents with credit-nsk-related contingent featues that are in a liabilty position as of December 31, 2009 was $11.8 milion. If
the credit-nsk-related contigent featues underlying these agreements were triggered on December 31, 2009, the Company would be
required to post $3.4 milion of collateral to its counterparies.
Credit Risk
Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparies of their
contractal obligations to deliver energy or make financial settements. The Company often extends credit to counterpares and
customers and is exposed to the nsk that it may not be able to collect amounts owed to the Company. Changes in market pnces may
dramatically alter the size of credit nsk with counterparies, even when conservative credit limits are established.
Credit risk includes potential counterpar default due to circumstaces:
· relating directly to it,
· caused by market pnce changes, and
· relating to other market parcipants that have a diect or indirect relationship with such counterpar.
Should a counterpar, customer or supplier fail to perform, the Company may be required to honor the underlying commitment or to
replace existing contrcts with contrcts at then-curent market pnces. The Company seeks to mitigate credit risk by:
· entering into bilateral contrcts that specifY credit terms and protections against default,
· applying credit limits and durtion critena to existing and prospective counterpares,
· actively monitonng curent credit exposures, and
· conductg some of its tranactions on exchages with clearg arangements that essentially eliminate counterpar default
risk.
These credit policies include an evaluation of the fiancial condition and credit ratigs of counterpares, collateral requirements or
other credit enhancements, such as letters of credit or parent company guantees. The Company also uses stadardizd agreements
that allow for the netting or offsetting of positive and negative exposures associated with a single counterpar or affliated group.
The Company has concentrations of suppliers and customers in the electrc and natul gas industres including:
· electrc utilties,
· electric generators and tranmission providers,
· natul gas producers and pipelines,
· fiancial intutions, and
· energy marketing and trdin companies.
In addition, the Company has concentrtions of credit nsk related to geogrphic location as it operates in the western United States and
western Canada These concentrations of counterpares and concentrations of geographic location may impact the Company's overall
exposure to credit nsk, either positively or negatively, because the counterparies may be simarly affected by changes in conditions.
As is common industr practice, A vist Corp. maintai margi agreements with cert counterpares. Margi calls are trggered
when exposurs exceed predetermined contractu limits or when there are changes in a counterpar's creditwortess. Pnce
movements in electrcity and natu gas can generate exposure levels in excess of these contractal limits. Margi calls are
penodically made and/or received by A vista Corp. Negotiatig for collatera in the form of cash, letters of credit, or performance
guartees is common industr practice.
Cash deposits from counterparies totaled $3.2 milion as of December 31,2009 and $0.2 milion as of December 3 1,2008. These
fuds were held by A vista Corp. to mitigate the potential impact of counterpar default nsk. These amounts are subj ect to retu if
IFERC FORM NO.1 (ED. 12-88) Page 123.9
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 0416/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
conditions warant because of continuing portolio value fluctutions with those pares or substitution of non-cash collateral.
NOTE 7. JOINTLY OWNED ELECTRC FACILITIES
The Company has a 15 percent ownership interest in a twin-unit coal-frred generating facilty, the Colstrp Generating Project
(Colstrp) located in southeastern Montaa, and provides financing for its ownership interest in the project. The Company's shae of
related fuel costs as well as operatig expenses for plant in service ar included in the correspondig accounts in the Statements of
Income. The Company's shae of utilty plant in servce for Colstrp was $334.8 millon and accumulated depreciation was $209.6
millon as of December 3 1,2009. The Company's share of utility plant in servce for Colstrp was $330.9 milion and accumulated
depreciation was $204.0 millon as of December 3 I, 2008.
NOTE 8. ASSET RETIRMENT OBLIGATIONS
The Company records the fair value of a liabilty for an asset retirement obligation in the period in which it is incured. When the
liabilty is initially recorded, the associated costs of the asset retirement obligation are capitaizd as par of the caring amount of the
related long-lived asset. The liabilty is accreted to its present value each penod and the related capitalizd costs are depreciated over
the useful life of the related asset. Upon retiement of the asset, the Company either settles the retirement obligation for its recorded
amount or incurs a gain or loss. The Company records regulatory assets and liabilties for the difference between asset retirement costs
curently recovered in rates and asset retirement obligations recorded since asset retirement costs are recovered though rates charged
to customers. The regulatory assets do not eam a retu.
Specifically, the Company has recorded liabilties for futue asset retiement obligations to:
. restore ponds at Colstrp,
. cap a landfill at the Kettle Falls Plant,
. remove plant and restore the land at the Coyote Sprigs 2 site at the termation of the land lease,
. remove asbestos at the corporate offce buiding, and
. dispose of PCBs in cert tranformers.
Due to an inabilty to estimate a range of settlement dates, the Company canot estimate a liabilty for the:
. removal and disposal of cert transmission and distribution assets, and
. abandonment and decommissionig of certin hydroelecic generation and natual gas storage facilties.
The following table documents the changes in the Company's asset retiment obligation durg the year ended December 3 I (dollars
in thousands):
Asset retiement obligation at begiing of year
New liabilty recognizd
Liabilty adjustment due to revision in estiated cash flows
Liabilty settled
Accretion expense
Asset retiement obligation at end of year
2009
$4,208
2008
$3,990
(499)
262nm
(29)
247~
NOTE 9. PENSION PLAS AND OTHER POSTRETIRMENT BENEFIT PLANS
The Company has a defied benefit pension plan coverig substtially al reguar ful-tie employees. Individua benefits under this
plan are based upon the employee's years of servce and average compensation as specifed in the plan. The Company's fuding
policy is to contrbute at leas the miimum amounts that are requied to be fuded under the Employee Retiement Income Securty
Act, but not more than the maximum amounts tht are curently deductible for income ta puroses. The Company contrbuted $48
milion in cash to the pension plan in 2009 and $28 milion in 2008. The Company expects to contrbut $21 miion to the pension
plan in 2010.
The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executve
offcers of the Company. The SERP is intended to provide benefits to executive offcers whose benefits under the pension plan are
reduced due to the application of Section 4 is of the Internal Revenue Code of 1986 and the deferr of salar under deferred
compensation plan. The liabilty and expense for this plan are included as pension benefits in the tables included in ths Note.
I FERC FORM NO.1 (ED. 12-88)Page 123.10
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)Avista Corpration 1(2) . A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The Company expects that benefit payments under the pension plan and the SERP will total $18.6 milion in 2010, $19.4 milion in
2011, $20.5 milion in 2012, $21.7 milion in 2013 and $23.0 milion in 2014. For the ensing five years (2015 though 2019), the
Company expects that benefit payments under the pension plan and the SERP wil total $136.3 milion.
The expected long-tenn rate of retu on plan assets is based on past perfonnance and economic forecasts for the tyes of investments
held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portolios with
matuties similar to that of the expected tenn of pension benefits.
In 2009, the Company reviewed the mortlity table utilizd in the actuarial calculations. The Company detennined that the RP-2000
combined healthy mortality tables for males and females should be replaced with the RP-2000 combined healthy mortity tables for
males and females projected to 2010 using scale AA. The change resulted in an increase of $6.6 millon to the pension benefit
obligation as of December 31, 2009.
In 2008, the rates at which parcipants are assumed to retie by age were analyzed based upon historical trends and futue projections.
The Company.revised the rates to assume that a greater percentage of parcipants would retie between the ages of 55 and 65. The
assumed rates were revised to rage from 5 percent to 40 percent and 100 percent at age 65. The previous rates ranged from 2 percent
to 30 percent and 100 percent at age 65. The change resulted in an increase of $ 11.0 milion to the pension benefit obligation as of
December 31,2008.
The Company provides certin health care and life inurce benefits for substatially all of its retied employees. The Company
acrues the estiated cost otpostretiement benefit obligations durg the years that employees provide servces. The Company
elected to amort the tranition obligation of$34.5 million over a period of twenty years, begiing in 1993.
The Company established a Health Reimbursement Argement to provide employees with ta-advantaged fuds to pay for allowable
medical expenses upon retiement. The amount eared by the employee is fied on the retirement date based on employees' years of
servce and the ending salar. The liabilty and expense of ths plan are included as other postretirement benefits.
The Company provides death benefits to beneficiares of executive offcers who die durg their term of offce or after retirement.
Under the plan an executive offcer's designated beneficiar wil receive a payment equal to twce the executive offcer's anual base
salar at the tie of death (or if death occurs after retirement, a payment equal to twice the executive offcer's tota anual pension
benefit). The liabilty and expense for this plan are included as other postretirement benefits.
The Company expects that benefit payments under other postretirement benefit plans will be $4.1 milion in 2010, $3.9 milion in
2011, $3.7 milion in 2012, $3.6 milion in 2013 and $3.5 milion in 2014. For the ensuing five years (2015 though 2019), the
Company expect that benefit payments under other postretiement benefit plan wil total $ 1 6.4 milion. The Company expect to
contrbute $4. I milion to other postretirement benefit plan in 2010, representing expected benefit payments to be paid durg the
year.
The Company uses a December 31 measurement date for its pension and other postretirement benefit plan. The following table sets
fort the pension and other postretiement benefit plan disclosures as of December 31,2009 and 2008 and the components of net
periodic benefit costs for the years ended December 31, 2009 and 2008 (dollars in thousands):
Change in benefit obligation:
Benefit obligation as of beginin of year
Servce cost
Interest cost
Actaral loss
Trafer of accrued vacation
Benefits paid
Benefit obligation as of end of year
Change in plan assets:
Fair value of plan assets as of beginning of year
Actu retu on plan assets
Employer contrbutions
IFERC FORM NO.1 (ED. 12-88)
Pension
2009 2008
$353,572
10,496
21,770
9,610
07,213)
$378,235
$323,090
10,209
20,812
17,041
07,580)
$353572
$190,637 $242,561
50,053 (63,575)
48,000 28,000
Page 123.11
Other
2009 2008
$38,953
803
2,364
1,676
98
(4,334)
$39560
$16,048
4,346
$34,352
772
2,371
5,611
365
(4.518)
$38953
$22,718
(6,670)
Name of Respondent This Report is:Date of Report Year/Period -of Report
(1) c An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/1612010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Benefits paid 05,958)06,349)----
Fair value of plan assets as of end of year $272,732 $190,637 $20394 $16048
Funded statu $(105,503).$(162,935)$(19,166)$(22,905)
Unrecognized net actual loss 126,926 160,280 15,772 18,357
Unrecognizd prior servce cost 1,790 2,444 (1,303)(1,452)
Unrecognized net transition obligation 1,16 2,021
Prepaid (accrued) benefit cost 23,213 (211)(3,181)(3,979)
Additional liabilty 028,716)062,724)05,985)08,926)
Accrued benefit liabilty $005,503)$(62935)$09,166)$(22905)
Accumulated pension benefit obligation $294,649 $307.413
Accumulated postretirement benefit obligation:
For retirees $18,377 $18,821
For fuly eligible employees $9,290 $8,903
For other paricipants $11,893 $11,229
Included in accumulated comprehensive loss (income) (net oftax):
Unrcognized net transition obligation $$$985 $1,313
Unrecognized prior servce cost 1,163 1,589 (847)(943)
Unrecognizd net actuial loss 82.502 104,182 10,252 11,932
Total 83,665 105,771 10,390 12,302
Less regulatory asset (80,041)(98,850)01.664)03.131)
Accumulated other comprehensive loss (income)~~$(274)$ (829)
Weighted average assumptions as of December 31:
Discount rate for benefit obligation 6.29%6.25%6.00%6.25%
Discount rate for anua expense 6.25%6.34%6.25%6.20%
Expected long-term retu on plan assets 8.50%8.50%8.50%8.50%
Rate of compensation increase 4.65%4.72%
Medical cost trend pre-age 65 - intial 8.50%9.00%
Medical cost trend pre-age 65 - ultiate 5.00%5.00%
Ultimate medical cost trend year pre-age 65 2017 2017
Medical cost trend post-age 65 - intial 8.50%9.00%
Medical cost trend post-age 65 - ultiate 6.00%6.00%
Ultimte medcal cost trend year post-age 65 2015 2015
Components of net periodic benefit cost:
Service cost $10,496 $10,209 $803 $772
Interest cost 21,770 20,812 2,364 2,371
Expected retu on plan assets (17,612)(21,138)(1,364)(1,931)
Transition obligaton recogntion 505 505
Amorttion of prior servce cost 654 654 (149)(149)
Net loss recognition 10,539 3,345 1.279 575
Net periodic benefit cost $25,847 $13.882 WJ ~
Plan Assets
The Finance Committe of the Company's Board of Directors:
. establishes investment policies, objectives and strategies th seek an appropriate retu for the pension plan and other
postretiement plan and
. reviews and approves changes to the investment and fudi poÌicies.
The Company has contracted with investment consultats who are responsible for managing/monitorig the individua investment
managers. The investent managers' performance and related individua fud performance is periodically reviewed by an intern
benefits committee and by the Finance Commtte to monitor compliance with investment policy objectives and strategies.
Pension plan assets are invested priily in marketble debt and equity securities. Pension plan assets may also be invested in real
estate, absolute retu, ventue capitaprivate equity and commodity fuds. In seekig to obtain the desired retu to fud the pension
plan the investment consultat recommends allocation percentages by asset classes. These recommendations are reviewed by the
IFERC FORM NO.1 (ED. 12-88) Page 123.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation '2) A Resubmission 04116/2010 2009/04
NOTES TO FINACIAL STATEMENTS (Continued)
internal benefits commttee, which then recommends their adoption by the Finance Committee. The Finance Commtte has
established taget investment allocation percentages by asset classes as of December 3 1,2009 and 2008 as indicated in the table below:
Equity securties
Debt securties
Real estate
Absolute retu
Oter
2009
51%
31%
5%
10%
3%
2008
50%
30%
5%
12%
3%
The market-related value of pension plan assets invested in debt and equity securties was based priarly on fair value (market
prices). The fair value of investment securties traded on a national securties exchange is determined based on the last reported sales
price; securities trded in the over-the-counter market are valued at the las reportd bid price. Investment securties for which market
prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the
investment manager based upon other inputs (including valuations of securties that are comparble in coupon, ratig, matuty and
industr). Investents in common/collective trst fuds are presented at estated fai value, which is determed based on the unit
value of the fud. Unit value is determined by an independent trstee, which sponsors the fud, by dividing the fud's net assets by its
units outstading at the valuation date. The fair value of the closely held investments and parership interests is based upon the
allocated share of the fair value of the underlying assets as well as the allocated share of the undistbuted profits and losses, including
realized and unalized gais and losses.
The market-related value of pension plan assets invested in real estate was determined by the investment manager based on thee basic
approaches:
· curent cost of reproducing a propert less deterioration and fuctional economic obsolescence,
· capitaization of the propert's net earings power, and
· value indicated by recent sales of comparable propertes in the market.
The market-related value of pension plan assets was determined as of December 31, 2009 and 2008.
The following table discloses by level within the fair value hierarchy (refer to Note 18 for a description of the fair value hierarchy) of
the pension plan's assets measured and reported as of December 31, 2009 at fai value (dollars in thousands):
Levell Level 2 Level 3 Tota$ 19 $ $ $ 19Cash equivalents
Mutual fuds:
Fixed income securities
U.S. equity securties
International equity securties
Absolute retu (1)
Commodities (2)
Common/collective trsts:
Fixed income securties
U.S. equity securties
Absolute retu (1)
Real estate
Parership/closely held investments:
Absolute retu (1)
Private equity fuds (3)
Total
70,924
87,562
46,548
11,671
5,870
70,924
87,562
46,548
11,671
5,870
14,840
11,070
844
6,029
14,840
11,070
844
6,029
$222,594 $25,910
15,794
1,561
$24,228
15,794
1,561
$272,732
(1) This category invests in multiple strategies to diverify risk and reduce volatilty. The strategies include: (a) event driven,
relative value, convertible, and fied income arbitrage, (b) distessed investments, (c) long/short equity and fied income and
(d) market neutral strategies.
(2) The fud priarily invests in derivatives lined to commodity indices to gain exposure to the commodity markets. The fud
manager fully collateralizes these positions with debt securties.
IFERC FORM NO.1 (ED. 12-88) Page 123.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/1612010 2009/04
NOTES TO FINACIAL STATEMENTS (Continued)
(3) This category includes severl private equity fuds th invest prily in U.S. companes.
The table below discloses the sum of changes in the fa value of the penion plan's Level 3 assets for the year ended December
3 I, 2009 (dollars in thousands):
Common/collective trts
Absoluteretu
$2,351
(415)
(21)
(1.071).l
Real
estate
$11,987
520
(4,310)
(2.168)~
Parership/closely held investments
Absolute Private equityretu fuds
$ 13,983 $1,316
31,811 223- --$15.794 ~
Balance, as of Janua 1,2009
Realizd gai (losses)
Unrealiz gains (losses)
Purchases (sales), net
Balance, as of December 31,2009
The market-related value of other postretiement plan assets invested in debt and equity securties was based priarly on fair value
(market prices). The fair value of investment securties tred on a natonal securties exchange is determined based on the last
repored sales price; securties traded in the over-the-counter market are valued at the last reported bid price. Investent securties for
which market prices are not readly available or for which market prices do not represent the value at the time of pricing, are
fair-valued by the investment mager based upon other inputs (including valuations of securties that are comparable in coupon,
rating, matuty and industr).
The market-related value of other posttiement plan assets was determed as of December 3 1,2009 and 2008.
The following table discloses by level within the fair value hierachy (refer to Note i 8 for a description of the fair value hierarchy) of
other postretiement plan assets measured and reportd as of December 3 I, 2009 at fai value (dollars in thousands):
Level i Level 2 Level 3 Total$ 96 $ $ $ 96Cas equivalents
Mutul fuds:
Debt securities
U.S. equity securities
Internationa equity securties
Debt securities
U.S. equity securties
International equity securties
Tota
7,742
5,927
5,077
25
1,456-B
$20394 $$
7,742
5,927
5,077
25
1,456-B
$20,394
Assumed health care cost trend rates have a signcant effect on the amounts reported for the health car plan. A
one-percentage-point increase in the assumed health care cost trend ra for each year would increase the accumulated postretiement
benefit obligation as of December 3 I, 2009 by $2. i millon and the service and interest cost by $0.2 milion. A one-percentage-point
decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as
of December 3 I, 2009 by $ 1.9 millon and the service and interest cost by $0.2 milion.
The Company has a salar deferr401(k) plan tht is a defied contrbution plan and covers substtialy all employees. Employees
can make contrbutions to their respectve accounts in the pla on a pre-ta basis up to the maxum amount permttd by law. The
Company matches a portion of the salar deferred by each parcipant accordig to the schedule in the plan. Employer matchig
contrbutions were $4.4 millon in 2009 and $4.3 milion in 2008.
The Company has an Executive Deferr Plan. Ths plan alows executive offcers and other key employees the opportty to defer
until the earlier of their retirement, termation, disabilty or death, up to 75 percent oftheÍl base salar and/or up to 100 percent of
their incentive payments. Deferred compensaton fuds are held by the Company in a Rabbi Trut At December 3 i, 2009 and 2008,
there were deferred compensation assets of$9.4 milion and $8.8 milion included in other special fuds and correspondig deferred
compensation liabilties of$9.4 millon and $8.8 milion included in other deferred credits on the Balance Sheets.
NOTE 10. ACCOUNTING FOR INCOME TAXES
IFERC FORM NO.1 (ED. 12-88) Page 123.14
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) ~ An Onginal (Mo, Da, Yr)
Avista Corporation (2) . A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Deferred income taes reflect the net ta effects of temporar differences between the caring amounts of assets and liabilties for
fiancial reporting puroses and the amounts used for income ta puroses and ta credit carorwards.
As of December 31,2009, the Company had $1 1.6 milion of state ta credit carforwards. State ta credits expire from 2015 to
2021. The Company recognizes the effect of state ta credits generated from utilty plant as they are utilized.
The realization of deferred income ta assets is dependent upon the abilty to generate taable income in futue periods. The Company
evaluated available evidence supportg the realiztion of its deferred income ta assets and determined it is more likely than not that
deferred income ta assets will be realizd.
The Company and its eligible subsidiares fie consolidated federal income ta retus. The Company also files state income ta
retus in certin jursdictions, including Idao, Oregon and Montaa. Subsidiares are charged or credited with the ta effects of their
operations on a stad-alone basis. The Internal Revenue Service (IRS) has completed its examination of all ta years though 2007
and all issues were resolved related to these years. The IR has not examined the Company's 2008 federal income ta retu. Ths
examination could result in a change in the liabilty for uncertin tax positions. However, an estiate of the rage ofany such possible
change canot be made at this time. The Company does not believe that any open ta year for state income taes could result in any
adjustments that would be significant to the fiancial statements.
In August 2005, the Treasur Deparent issued regulations and the IRS issued a revenue ruling that affects the ta treatment by
A vista Corp. of certin indirect overhead expenses. A vista Corp. had previously made a ta election to curently deduct certin
indirect overhead costs, stag with the 2002 ta retu that were capitaized for fiancial accountin puroses. This election
allowed A vita Corp. to tae ta deductions resultig in a tota reduction of approximately $40 milion in curent ta liabilties for
2002, 2003 and 2004. These curent ta benefits were deferred on the balance sheet and did not affect net income.
On the basis of the revenue ruling and related regulations, the IRS disallowed the ta deduction of indirect overhead expenses durg
their examation of the Company's 2001, 2002 and 2003 federal income ta retu. The Company believed that the ta deductions
claimed on ta retus were appropnate based on the applicable statutes and regulations in effect at the tie. A vist Corp.
appealed the proposed IRS adjustment in Apnl 2006. The Company repaid a portion of the previous ta deductions though ta
payments in 2005, 2006 and 2008.
On September 10,2008, the Company entered into a Settlement Agreement with the Appeals Division of the IRS that resolved all
items noted durg their audit of the Company's 2001 thoug 2003 ta year, including, among other thgs, indirect overhead
expenses. The agreement was reviewed and approved by the Joint Committee on Taxation, and a settement payment was received in
December 2008. The onginal IR disallowance and the Company's appeal of the indirect overhead issue caused a delay in associated
ta refuds for net operating losses that were caried back to several earlier year. The fmal settement with the IR freed up the
refud years and set the amount owed for the 2001-2003 ta year. The net result was a refud to the Company of$14.7 milion, plus
interest of$5.7 milion.
The Company had net regulatory assets of$97.9 milion at December 31, 2009 and $115.0 milion at December 31, 2008 related to the
probable recovery of certin deferred income ta liabilties from customers though futue rates.
NOTE 11. ENERGY PURCHASE CONTRACTS
A vista Corp. has contrcts for the purchase of fuel for thermal generation, natual gas for resale and varous agreements for the
purchase or exchange of electrc energy with other entities. The termintion dates of the contracts range from one month to the year
2055. Tota expenses for power purchased, natual gas purchased, fuel for generation and other fuel costs, which are included in
operaton expenses in the Statements of Income, were $704.9 milion in 2009 and $951.4 millon in 2008. The followig table details
A vista Corp.' s futue contrctu commitments for power resources (including transmission contracts) and natual gas resources
(includig transporttion contracts) (dollars in thousands):
2010 2011 2012 2013 2014 Thereafter Tota
Power resources $220,286 $133,287 $104,716 $ 79,543 $70,605 $485,980 $1,094,417
Natul gas resources 146,321 93,609 62.084 44,375 44.424 431,904 822,717
Total $366.607 $226896 $166,800 $123918 $115.029 $917884 $1.917 134
These energy purhase contracts were entered into as par of A vista Corp.' s obligation to serve its retail electrc and natal gas
IFERC FORM NO.1 (ED. 12-88)Page 123.15
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo. Da, Yr)
Avista Corpration I (2) A Resubmission 0411612010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
customers' energy requiements. As a result, these costs are generaly recovered either though base retal rates or adjustments to retal
rates as par of the power and natual gas cost deferral and recovery mechansms.
In addition, A vista Corp. has operational agreements, settlements and other contrctual obligations for its generation, trsmission and
distribution facilties. The expenses associated with these ageements are reflected as operation expenses and maintenance expenses in
the Statements of Income. The followig tale detas futue contractl commtments for these agreements (dollar in thousands):
Contractu obligations
2010
$46773
2011
$55,084
2012
$48,457
2013
$52,181
2014
$53,211
Thereafter
$573,643
Tota
$829,349
Avista Corp. has fied contracts with certain Public Utility Districts (PUD) to purchase portons of the output of certin generatig
facilties. Although A vista Corp. has no investment in the PUD generatig facilties, the fixed contracts obligate Avista Corp. to pay
certin minum amounts (based in par on the debt service requirements of the PUD) whether or not the facilties are operating. The
cost of power obtaed under the contracts, includig payments made when a facilty is not operating, is included in operation expenses
in the Statements of Income. Expenses under these PUD contracts were $12.6 millon in 2009 and $14.9 millon in 2008. Inonnation
as of December 31,2009 pertining to these PUD contrcts is sumarzed in the following table (dollars in thousands):
Company's Curent Share of
Debt Expir-
Kilowat Anua Service Bonds tion
Output i Capabilty Costs (1)Costs (1)Outstading Date
Chelan County PUD:
Rocky Reach Project 2.9%37,000 $ 1,658 $883 $ 909 2011
Douglas County PUD:
Wells Project 3.5%30,000 1,609 698 3,728 2018
Grant County PUD:
Prest Rapids Project 3.3%31,500 4,377 726 7,854 2055
Wanapum Project (2)7,4%76,800 4,989 2,394 13,554 2055
Totas 175,300 $12633 ~$26,045
(1) The anua costs wil change in proportion to the percentage of output allocated to A vista Corp. in a parcular year. Amounts
represent the operating costs for the year 2009, Debt service costs are included in anua costs. ,
(2) A previous contract expired on October 31,2009. A new contract was completed in 2001 with an expiration date of2055.
Begig in November 2009, the Company's rights to the output were reduced from 8.2 percent to 3.3 percent. Under the new
contract the Company has the rights to the output but not the obligation to tae the output. In September of each year the
Company is requird to determe if it wil tae the output for the subsequent year.
The estiated aggegate amounts of requied minum payments (A vita Corp.'s share of existing debt service costs) under these PUD
contracts are as follows (dollars in thousands):
Minimum payments
2010~2011~2012~2013~2014~Thereafer
$30,777
Tota
$44,052
In addition, Avista Corp, wil be requied to pay its proportonate share of the varable operating expenses of these projects,
NOTE 12. NOTES PAYABLE
Avista Corp. ha a committed line of credit agreement with varous ban in the tota amount of $320.0 milion with an expiration date
of April 5, 201 1. Under the credit agreement, the Company can borrow or request the issuace of letters of credit in any combination
up to $320.0 millon. Tota lettrs of credit outsding were $28.4 miion as of December 31, 2009 and $24,3 millon as of
December 31,2008. The committed line of credit is secured by $320.0 milion of non-tranferable Firt Mortgage Bonds of the
Company issued to the agent ban that would only become due and payable in the event, and then only to the extent, tht the Company
defaults on its obligations under the commtted line of credit.
Additionally, the Company has a committed line of credit agreement with varous ban in the tota amount of$75.0 millon with an
expiration date of April 5, 2011. Avista Corp. may elect to increase the commttd line of credit by up to $25.0 millon under the same
agreement. The committed line of credit is secured by $75.0 milion of non-trferable First Mortgage Bonds of the Company issued
IFERC FORM NO.1 (ED. 12-88) Page 123.16 I
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1)2SAn Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 0416/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
to the agent ban that would only become due and payable in the event, and then only to the extent, that the Company defaults on its
obligations under the committed line of credit.
The committed line of credit agreements contain customar covenants and default provisions, including a covenant requiring the ratio
of "eargs before interest, taxes, depreciation and amortization" to "interest expense" of Avista Corp. for the preceding
twelve-month period at the end of any fiscal quaer to be greater than 1.6 to i. As of December 3 i, 2009, the Company was in
compliance with this covenant with a ratio of 4.23 to i. The committed line of credit agreements also have a covenant which does not
permt the ratio of "consolidated total debt" to "consolidated total capitalition" of Avista Corp. to be greater than 70 perent at any
time. As of December 31,2009, the Company was in compliance with this covenat with a ratio of 53.6 percent.
Balances outstading and interest rates of borrowigs (excluding letters of credit) under the Company's revolvig committd lines of
credit were as follows as of and for the years ended December 31 (dollas in thousands):
Balance outstanding at end of period
Maximum balance outstading durg the period
Average balance outsding during the period
Average interest rate durg the period
Average interest rate at end of period
2009
$ 87,000
$275,000
$186,474
0.65%
0.59%
2008
$250,000
$250,000
$ 48,426
3.04%
0.81%
NOTE 13. BONDS
The following detals bonds outstading as of December 31 (dollar in thousands):
Matuty Interest
Year Description Rate 2009 2008
2010 Secured Medium-Term Notes 6.67%-8.02%$35,000 $ 35,000
2012 Secured Medium-Term Notes 7.37%7,000 7,000
2013 First Mortgage Bonds 6.13%45,000 45,000
2013 First Mortgage Bonds 7.25%30,000 30,000
2018 First Mortgage Bonds 5.95%250,000 250,000
2018 Secured Medium-Term Notes 7.39%-7.45%22,500 22,500
2019 Firt Mortgage Bonds 5.45%90,000 90,000
2022 First Mortgage Bonds (1)5.13%250,000
2023 Secured Medium-Term Notes 7.18%-7.54%13,500 13,500
2028 Secured Medium-Term Notes 6.37%25,000 25,000
2032 Secured Pollution Control Bonds (2)(2)66,700 66,700
2034 Secured Pollution Control Bonds (3)(3)17,000 17,000
2035 First Mortgage Bonds 6.25%150,000 150,000
2037 First Mortgage Bonds 5.70%150,000 150,000
Total secured bonds 1,151,700 901,700
2023 Unsecured Pollution Control Bonds 6.00%4,100 4,100
Interest rate swaps (1,844)(14,129)
Tota 1,153,956 891,671
Secured Pollution Control J30nds held by A vista
Corporation (2) (3)(83,700)(66,700)
Total bonds $1070256 $824,971
(I) In September 2009, the Company issued $250.0 milion of5.125 percent First Mortgage Bonds due in 2022.
(2) On December 31,2008, $66.7 milion of the City of Forsyt, Montaa Pollution Control Revenue Refuding Bonds, Series
1999A (Avista Corporation Colstrp Project) due 2032 were remareted. Avista Corp. purchased these Pollution Control
Bonds and expects that at a later date, subject to market conditions, these bonds wil be remarketed to unafliate investors or
refuded by a new issue. Although Avista Corp. is now the holder of these Pollution Control Bonds, the bonds will not be
cancelled but wil remain outstading under the City of Forsyt's indentue. However, so long as Avista Corp. is the holder,
the bonds wil not be reflected as an asset or a liabilty on A vista Corp. 's Balance Sheet.
IFERC FORM NO.1 (ED. 12-88) Page 123.17
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 0416/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(3) In December 2008, the City of Forsyt Montaa issued $17.0 milion of its Pollution Control Revenue Refudig Bonds,
Series 2008 (A vista Corp. Colstrip Project) due 2034 on behaf of Avista Corp. The proceeds of the Bonds were used to
refud $17.0 millon of Pollution Control Revenue Refudig Bonds, Senes 1999B (Avista Corp. Colstip Project) issued by
the City of Forsyt, Montana on beha of Avista Corp., which were subject to remarketing or refuding on December 31, -
2008. In December 2009, Avista Corp. purchased the Bonds and expects that at a later date, subject to market conditions, the
bonds wil be refuded or remaketed to unaffliated investors. Althoug Avista Corp. is now the holder of these Pollution
Control Bonds, the bonds will not be cancelled but wil remain outstadin under the City of Forsyt's indentue. However,
so long as Avista Corp. is the holder, the bonds wil not be reflected as an asset or a liabilty on Avista Corp.'s Balance Sheet
The followig table detals futue long-term debt matuties includig advances from associated companies (see Note 14) (dollar in
thousands):
Debt matuties .
2010
$35.000
2011~2012~2013 2014 Thereafter
$75000 $ - $1'006.647
Total
$1.123,647
Substatially all utilty properties owned by the Company are subject to the lien of the Company's mortgage indentue. Under the
Mortgage and Deed of Trut securg the Company's Fir Mortgage Bonds (including Secured Medium-Term Notes), the Company
may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of: 1) 70 percent of the cost or fai value
(whichever is lower) of propert additions which have not previously been made the basis of any application under the Mortage, or 2)
an equal principal amount of retired Firt Mortgage Bonds which have not previously been made the basis of any application under the
Mortgage, or 3) deposit of cash; provided, however, that the Company may not issue any additional First Mortgage Bonds (with
certin exceptions in the case of bonds issued on the basis of retied bonds) uness the Company's "net earings" (as dermed in the
Mortgage) for any penod of 12 consecutve caenda month out of the precedig 18 calenda month were at least twce the anua
interest requirements on all mortage securties at the tie outstading, includig the First Mortgage Bonds to be issued, and on all
indebtedness of prior ran. As of December 31, 2009, propert additions and retied bonds would have entitled the Company to issue
$668.5 milion in aggegate pricipal amount of additional Firt Mortgage Bonds. However, using an interest rate of 8 percent on
additional First Mortgage Bonds, and based on net eargs for the 12 month ended December 3 1,2009, the net earings test would
limt the pricipal amount of additional bonds the Company could issue to $607.5 millon.
See Note 12 for inormtion regardig First Mortgage Bonds issued to secure the Company's obligations under its $320.0 millon and
$75.0 milion committed line of credit ageements.
NOTE 14. ADVANCES FROM ASSOCIATED COMPANIES
In 2004, the Company issued Junor Subordinated Debt Securties, with a pricipal amount of $6 1.9 millon to A V A Capita Trut II,
an affliated business trt formed by the Company. Concurently, AVA Capital Trust II issued $60.0 milion of Preferred Trust
Securities to third pares and $1.9 millon of Common Trut Securties to the Company. On April 1,2009, AVA Capita Trut II
redeemed all of the Preferred Trut Securties issued to thd pares with a pricipal balance of$60.0 millon and all of the Common
Trut Securties issued to the Company with a pricipal balance of$1.9 milion. Concurently, the Company redeemed the total
amount outstanding of its Junor Subordinted Debt Securties, at 100 percent of the pricipal amount ($61.9 milion) plus accrued
interest held by AVA Capital Trut III. The Company's net redemption of$60.0 millon was fuded by borrowings under its $320.0
milion commtted line of credit agreement.
In 1997, the Company issued Floating Rate Junor Subordinated Deferrable Interest Debentues, Senes B, with a pricipal amount of
$51,5 milion to Avista Capital II, an afliated business tr formed by the Company. A vista Capital II issued $50.0 million of
Preferred Trust Securties with a floatig distrbution rate of LffOR plus 0.875 percent, calculated and reset quarerly. The anual
distribution rate paid durg 2009 ranged from 1.22 percentto 3.06 percent As of December 3 1,2009, the anua distrbution rate
was 1.22 percent Concurent with the issuance of the Preferred Trut Securties, A vista Capital II issued $1.5 milion of Common
Trut Securties to the Company. These debt seurties may be redeemed at the option of Avista Capita II on or af June 1,2007 and
matue on June 1,2037. In December 2000, the Company purhased $10.0 inion of these Preferred Trut Securties.
The Company has guanteed the payment of distrbutions on, and redemption price and liquidation amount for, the Preferred Trut
Securities to the extent that A vista Capita II has fuds available for such payments from the respective debt securties. Upon matuty
or prior redemption of such debt securties, the Preferred Trut Securities will be mandatonly redeemed.
NOTE is. LEASES
IFERC FORM NO.1 (ED. 12-88) Page 123.18
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation i2) A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The Company has multiple lease argements involving varous assets, with minimum tenn raging from one to fort-five years.
Renta expense under operating leases was $3.2 milion in 2009 and $2.0 milion in 2008. Futue minimum lease payments required
under operating leases having initial or remaining noncancelable lease terms in excess of one year as of December 31, 2009 were as
follows (dollars in thousands):
Minimum payments requied
2010 20llaw~2012 2013~~2014~Thereafer~Totalam
NOTE 16. GUAREES
The Company has guanteed the payment of distrbutions on, and redemption price and liquidation amount for, the Preferred Trut
Securities issued by its afliate, A vista Capital II, to the extnt that this entity has fuds available for such payments from its debt
securties.
The output from the Lancaster Plant is contracted to Avista Turbine Power, Inc. (ATP), an affliate of Avista Energy, though 2026
under a power purchase agreement. Avista Corp. has provided Rathdr Power LLC, the owner of the Lancaster Plant, a gutee
under which A vista Corp. has guaranteed A TP's performance under the power purchase agreement. The majority of the rights and
obligations of this agreement were conveyed to Shell Energ though the end of 2009. Begiing in Januar 2010, the rights and
obligations under the power purchase agreement were conveyed to Avista Corp.
In connection with the tranaction, on June 30, 2007, Avista Energy and its afliates entered into an Indemnification Agreement with
Shell Energy and its afliates. Under the Indemnfication Agreement, A vista Energy and Shell Energy each agree to provide
indemnification of the other and the other's affiates for certin events and matters described in the purchase and sale agreement
entered into on April 16, 2007 and cert other tranaction agreements. Such events and matters include, but are not limited to, the
refud proceedings aring out of the western energy makets in 2000 and 2001 (see Note 22), existing litigation, ta liabilties, and
mattrs related to storae rights at Jackson Praie. In general, such indemnfication is not required unless and until a par's claims
exceed $150,000 and is limited to an aggegate amount of$30 milion and a term of thee years (except for agreements or transactions
with terms longer than thee years). These limitations do not apply to certin third par claim.
Avista Energy's obligations under the Indemnificaton Agreement ar guaranteed by Avista Capital pursuant to a Guaanty dated June
30,2007. This Guaranty is limited to an aggegate amount of$30 milion plus cert fees and expenses. The Guaty wil termate
April 30, 2011 except for claim made prior to termination. The Company has not recorded any liabilty related to this guty.
NOTE 17. PREFERRD STOCK-CUMULTIV (SUBJCT TO MANDATORY REDEMPTION)
The Company has 10 milion authorized shares of preferred stock. The Company did not have any preferred stock outstading as of
December 3 i, 2009 and 2008.
NOTE 18. FAff VALUE
Fair value represents the price that would be received to sell an asset or paid to trsfer a liabilty (an exit price) in an orderly
transaction between market parcipants at the measurement date. The caring values of cash and cash equivalents, special deposits,
accounts and notes receivable, accounts payable and notes payable are reasonable estiates of their fair values. Bonds and advaces
from associated companies are reported at carg value on the Balance Sheets.
The followig table sets fort the caring value and estiated fair value of the Company's fiancial instrents not reported at
estated fair value on the Balance Sheets as of December 31, 2009 and 2008 (dollar in thousands):
Bonds
Advances from associated companies
2009Carg Estiated
Value Fair Value
$1,072,100 $1,079,857
51,547 43,534
2008
Caring
Value
$839,100
113,403
Estiated
Fair Value
$875,451
102,027
These estiates of fai value were priarly based on available maret information.
Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatiVes related to interest rate swap
IFERC FORM NO.1 (ED. 12-88) Page 123.19
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 041612010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
agreements and foreign curency exchange contracts, are reportd at estiated fai value on the Balance Sheets. U.S. GAA defies a
fair value hierachy that prioritizs the inputs used to measure fai value. The hierarchy gives the highest priority to undjusted quoted
prices in active markets for identical assets or liabilties (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3
measurement).
The thee levels of the fair value hierarchy are defied as follows:
Levell - Quoted prices are available in active makets for identical assets or liabilties. Active markets are those in which
transactions for the asset or liabilty occur with suffcient frequency and volume to provide pricing infomiation on an ongoing
basis.
Level 2 - Prcing inputs are other than quoted prices in active makets included in Levell, which are either diectly or
indirectly observable as of the reporting date. Level 2 includes those ficial intrents that are valued using models or
other valuation methodologies. These models ar prily industr-stadard models that consider various assumptions,
including quoted forward prices for commodities, tie value, volatilty factors, and curent maket and contractul prices for
the underlying instrents, as well as other relevant economic measures. Substatially all of these assumptions are
observable in the marketplace thoughout the ful temi of the intrent, can be derived from observable data or are
supported by observable levels at which tranactions are executed in the marketplace.
Level 3 - Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may
be used with internally developed methodologies that result in management's best estimate offair value. Level 3 instrents
include those that may be more strctued or otherwse tailored to the Company's needs.
Financial assets and liabilties are classified in their entiety based on the lowest level of Ülput that is signcant to the fai value
measurement. The Company's assessment of the signcance of a parcular inut to the fair value measurement requies judgment,
and may affect the vauation of fai value assets and liabilties and their placement with the fair value hierarchy levels. The
detemiination of the fair values incorporates vaous factrs that not only include the credit stading of the counterpares involved and
the impact of credit enhancements (such as cash deposits and lettrs of credit), but alo the impact of Avista Corp.'s nonperfomiance
risk on its liabilties.
The following table discloses by level with the fair value hierarchy the Company's assets and liabilties measured and reportd on the
Balance Sheets as of December 31, 2009 and 2008 at fair value on a recuring basis (dollars in thousands):
Counterpar
Levell Level 2 Level 3 Netting (I) Total
December 31, 2009
Assets:
Energy commodity derivatives
Deferred compensation assets.:
Fixed income securities (2)
Equity securties (2)
Tota
Liabilties:
Energy commodity derivatives
Foreign curency derivatives
Total
December 31, 2008
Assets:
Energy commodity dervatives
Deferred compensation assets:
Fixed income securties (2)
Equity securties (2)
Interest rate swaps
Tota
Liabilties:
Energy commodity derivatives
IFERC FORM NO.1 (ED. 12-88)
$
2,011
5,863n.
$
L.
$
1,889
5,101~
L.
$11,898 $57,276 $(15,934)
----
$11,98 $57,276 $05,934)
$27,086 $7,806 $(15,934)----
$27 136 ~$(15,934)
$40,104 $68,047 $(47,604)
875
$40,979 $68047
$16085
$(47,604)
$1 lQ,123 $(47,604)
Páge 123.20
$53,240
2,011
5,863
$61 114
$18,958--
$19,008
$60,547
1,889
5,101--
$68:412
$78604
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)Avista Corporation (2) A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(1) The Company is permittd to net derivative assets and derivative liabilties when a legally enforceable master nettng
agreement exists.
(2) These assets are trading securities.
A vista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or durg a specified
period, in the futue. These contrcts are entered into as par of A vista Corp. ' s management of loads and resources and certin
contracts are considered derivative intrents. The difference between the amount of derivative assets and liabilties disclosed in
respective levels and the amount of derivative assets and liabilties disclosed on the Balance Sheets is due to nettg argements with
certin counterparies. The Company uses quoted market prices and forward price cures to estiate the fair value of utilty derivative
commodity instrments included in Level 2. In paricular, electric derivative valuations are performed using broker quotes, adjusted
for periods in between quotable periods. Natual gas derivative valuations are estiated using New York Mercantile Exchange
(NX) pricing for similar intrents, adjusted for basin differences, using broker quotes. Where observable inputs are available
for substatially the full term of the contract, the derivative asset or liabilty is included in Level 2. The Company also has cert
contracts that, priarly due to the lengt of the respective contract, require the use ofintemally developed forward price estiates,
which include significant inputs that may not be observable or corroborated in the market. These derivative contracts are included in
Level 3. Refer to Note 6 for fuer discussion of the Company's energy commodity derivative assets and liabilties.
Deferred compensation assets and liabilties represent fuds held by the Company in a Rabbi Trust for an Executive Deferral Plan.
These fuds consist of actively traded equity and bond fuds with quoted prices in active markets. The balance disclosed in the table
above excludes cash and cash equivalents of$1.6 miion as of Decmber 31, 2009 and $1.8 milion as of December 31, 2008.
The followig table presents activity for energy commodity dervative assets and (liabilties) measured at fair value using significant
unobservable input (Level 3) for the year ended December 31 (dollars in thousands):
Balance as of Janua 1
Total gains or losses (realized/unealized):
Included in net income
Included in other comprehensive income
Included in reguatory assetsiabilties (1)
Puchases, issuances, and settlements, net
Trasfers to other categories
Ending balance as of December 31
Assets
2009
$68,047
2008
$98,943
Liabilties
2009 2008
$(16,085) $(36,506)
(7,202)
(3,569)
(22,586)
(8,310)
7,747
532
18,715
1,706
$68047 $(7806)$(J6,085)$57276
(1) The WUC and the IPUC issued accountig orders authorizg Avista Corp. to offset commodity derivative assets or liabilties
with a regulatory asset or liabilty. This accounting treatment is intendèd to defer the recogntion of mark- to-market gain and losses
on energy commodity transactions until the period of settlement. The orders provide for Avista Corp. to not recogniz the unealized
gain or loss on utilty derivative commodity instrents in the Statements of Income. Realizd gains or losses are recognized in the
period of settlement, subject to approval for recovery though retail rates. Realized gains and losses, subject to regulatory approval,
result in adjustments to retail rates though purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho,
and periodic general rates cases.
NQTE 19. COMMON STOCK
The Company has a Direc Stock Puchase and Dividend Reinvestment Plan under which the Company's shareholders may
automatically reinvest their dividends and make optional cash payments for the purchase of the Company's common stock at curent
market value.
The payment of dividends on common stock is restrcted by provisions of certain covenants applicable to preferred stock contained in
the Company's Aricles ofIncorporation, as amended.
In December 2009, the Company entered into an amended and restated sales agency agreement with a sales agent to issue up to 1.25
milion shares of its common stock from time to time. The Company originally entered into a sales agency agreement to issue up to 2
milion shares of its common stock in December 2006. In 2008, the Company issued 750,000 shares of its common stock under this
IFERC FORM NO.1 (ED. 12-88) Page 123.21
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) ~ An Onginal (Mo, Da, Yr)
Avista Corporation (2) A Resubmission '041161010 2009104
NOTES TO FINANCIAL STATEMENTS (Continued)
sales agency agreement. The Company did not issue any shars under th sales agency ageement in 2009.
NOTE 20. EARGS PER COMMON SHA ATTRIUTABLE TO A VITA CORPORATION
The following table presents the computon of basic and diluted eargs per common share attibutble to Avista Corporation for
the year ended December 31 (in thousands, except per share amounts):
Numerator:
Net income attbutable to A vista Corporation
Subsidiar earings adjustment for dilutive securities
Adjusted net income attbutable to Avista Corporation
for computation of diluted eargs per common shae
Denominator:
Weighted-average number .of common shares
outstading-basic
Effect of dilutive securties:
Contingent stock awards
Stock options
Weighted-average number of common sharesoutstading-diluted ~
Earnings per common share attributable to Avista Corporation:Basic W,
WB
2009 2008
$87,071--$73,620
(249)
$86,957 $73,371
54,694 53,637
163~213~
Diluted
~ll~
Tota stock options outstading excluded in the calculation of diluted eargs per common shae attbutable to Avita Corporation
were 2 i 8,450 for 2009 and 250,950 for 2008. These stock options were excluded from the calculation because they were antidilutive
based on the fact that the exercise pnce of the stock options was higher than the average maket pnce of Avista Corp. common stock
during the respective penod.
NOTE 21. STOCK COMPENSATION PLAS
1998 Plan
In 1998, the Company adopted and shareholders approved, the Long-Term Incentive Pla (1998 Plan). Under the 1998 Plan, cert
key employees, offcers and non-employee diectors of the Company and its subsidiares may be granted stock options, stock
appreciation nghts, stock awards (including restrcted stock) and other stock-based awards and dividend equivalent nghts. The
Company ha available a maxum of3.5 millon shaes of its common stQck for grt under the 1998 Plan. As of December 31,
2009, 0.7 milion shares were remag for grt under this plan.
2000 Plan
In 2000, the Company adopted a Non-Offcer Employee Long-Term Incentive Plan (2000 Plan), which was not requied to be
approved by shareholders. The provisions of the 2000 Plan are essentially the same as those under the 1998 PLan except for the
exclusion of non-employee directors and executive offcers of the Company. The Company has available a maximum of 2.5 milion
shares of its common stock for grt under the 2000 Plan. However, the Company curently does not plan to issue any fuer options
or securities under the 2000 Plan. As of December 31, 2009, 1.7 milion shars were remaining for grt under ths plan.
Stock Compensation
The Company records compensation cost relatg to share-based payment tranactions in the ficial statements based on the fa
value of the equity or liabilty instrents issued. The Company recorded stock-based compensation expense of$2.9 millon for 2009
and $3.0 millon for 2008. The tota income ta benefit recognizd in the Statements of Income was $1.0 milion for 2009 and $ 1.1
milion for 2008.
Stock Options
The following sumarzes stock options activity under the 1998 Plan and the 2000 Plan for the year ended December 31:
2009 2008
Number of shares under stock options:
IFERC FORM NO.1 (ED. 12-88) Page 123.22
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Options outstading at beging of year
Options grted
Options exercised
Options canceled
Options outstading and exercisable at end of year
Weighted average exercise price:Options exercised $13.83Options canceled $22.69
Options outstading and exercisable at end of year $16.30
Intric value of options exercised (in thousands) $1,180
Intric value of options outstading (in thousands) $2,774
Infonnion for options outstading and exercisable as of December 31, 2009 is as follows:
Rage of
Exercise Prices
$10.17-$12.41
$15.88-$19.34
$20.11-$23.00
$26.59-$28.47
Total
Weighted
Average
Exercise
Price
$11.1
16.56
22.46
27.69
$16.30
Nwnber
of Shares
285,323
11,200
213,050
14.400
523,973
748,673
(200,225)
(24.475)
523,973
Weighted
Average
Remaining
Life (in years)
2.4
2.0
0.9
0.2
1.7
1,411,911
(582,238)
(81.000)
748673
$13.91
$21.70
$15.85
$4,248
$2,643
Total cash received from the exercise of stock options was $2.8 millon for 2009 and $8.1 milion for 2008. As of December 31,2009
and 2008, the Company's stock options were fully vested and expensed.
Restricted Shares
Restricted shares vest in equal thirds each year over a thee-year period and are payable in A vista Corp. common stock at the end of
each year if the service condition is met. In addition to the servce condition, the Company must meet a retu on equity taget in
order for the CEO's restrcted shares to vest. Durg the vesting period, employees are entitled to dividend equivalents which are paid
when dividends on the Company's common stock are declared. Restrcted stock is valued at the close of maket of the Company's
common stock on the grant date. The weighted average remaining vesting period for the Company's restrcted shares outstading as
of December 31, 2009 was one year. The followig table summarizs restrcted stock activity for the years ended December 31:
Unvested shaes at begining of year
Shares granted
Shares cancelled
Shares vested
Unvested shares at end of year
Weighted average fair value at grant date
Unrecogniz compensation expense at end of year (in thousands)
Intric value, unvested shares at end of year (in thousands)
Intric value, shares vested durg the year (in thousands)
2009
55,939
44,400
(10,000)
(18.435)~
$18.18
$668
$1,552
$345
2008
28,137
43,400
(1,230)
(14,368)~
$20.05
$691
$1,084
$293
Performnce Shares
Peñormance share grants have vestig periods of thee years. Peñormance awards entitle the recipients to dividend equivalent rights,
are subject to foñeitue under certin circumtaces, and are subject to meetig specific performance conditions. Based on the
attinent of the peñormance condition, the amount of cash paid or common stock issued will rage from 0 to 150 percent of the
peñormance shares granted depending on the change in the value of the Company's common stock relative to an external benchmark.
Dividend equivalent rights are accwnulated and paid out only on shares that eventually vest.
Peñormance share awards entitle the grtee to shares of common stock or cash payable once the servce condition is satisfied. Based
on attinent of the performance condition, grantees may receive 0 to 150 percent of the original shares granted. The peñormance
IFERC FORM NO.1 (ED. 12-88) Page 123.23
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corpration (2) A Resubmission 0411612010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
condition used is the Company's Tota Shaeholder Retu performance over a thee-year penod as compared against other utilities;
this is considered a market-based condition. Performce shaes may be settled in common stock or cash at the discretion of the
Company. Histoncally, the Company ha settled these awards though issuace of stock and intends to continue this practice. These
awards vest at the end of the thee-year penod. Performance shares are equity awards with a market-based condition, which results in
the compensation cost for these awards being recognzed over the requisite servce period, provided that the requisite service penod is
rendered, regardless of when, if ever, the market condition is satsfied.
The Company measures (at the grant date) the estiated fai value of performce shares granted. The fair value of each performance
shar award was estimated on the date of grt using a statitical model that incorporates the probabilty of meeting performance
tagets based on histoncal retu relative to a peer group. Expected volatility was based on the histoncal volatilty of A vist Corp.
common stock over a thee-year period. The expected term of the performance shares is thee years based on the performance cycle.
The nsk.free interest rate was based on the U.S. Treasur yield at the time of grant. The compensation expense on these awards wil
only be adjusted for changes in forfeitues. The following sumars the weighted average assumptions used to determine the fai
value of performce shares and related compensation expense as well as the resulting estiated fair value of performance shares
granted:
2009Risk.free interest rate 1.3%Expected life~ in years 3Expected volatilty 25.8%Dividend yield 3.6%
Weighted average grant dae fai value (per share) $17.22
The fair value includes both performance shares and dividend equivalent nghts.
The following sumars performce share actvity:
2008
2.2%
3
20.2%
2.8%
$16.96
2009 2008
Opening balance ofunvested performance shares 252,923 207,841Performance shares granted 163,900 170,100
Performance shares canceled (43,758) (5,239)
Performance shares vested (72.464) 019.779)
Ending balance ofunvested performce shares 300,601 252,923
Intric value ofunvested performance shaes (in thousands) $6,490 $4,902
Unrecognized compensation expense (in thousands) $2,453 $2,227
The weighted average remaiing vesting penod for the Company's performance shares outstading as of December 31, 2009 was 1.5
years. Unrecognd compensation expense as of December 31, 2009 wil be recognized during 20 i 0 and 20 Ii. The followig
sumars the impact of the market condition on the vested performance shaes:
Performance shares vested
Impact of market condition on shares vested
Shares of common stock eared
Intric value of common stock eared (in thousands)
2009
72,464
(72.464)
$
2008
119,779
21.560
14L339
$2,739
In 2009 and 2008, the number of performance shars veste was adjusted by (100) percent and 18 percent based on the performance
condition achieved. Shares eared under this plan are distrbute to parcipants in the quar followig vestig.
Awards outstading under the performance share grts include a dividend component that is paid in cash. Ths component of the
performce share grants is accounted for as a liailty award. These liabilty awards are revalued on a quaerly basis tag into
account the number of awards outstading, hitorical dividend rate, and the chage in the value of the Company's common stock
relative to an external benchmark. Over the life of these awards, the cumulative amount of compensation expense recogned wil
match the actul cash paid. As of December 31, 2009 and 2008, the Company had recognized compensation expense and a liabilty of
$0.3 millon and $0.5 milion related to the dividend component of performance share grants.
NOTE 22. COMMITMENTS AND CONTINGENCIES
IFERC FORM NO.1 (ED. 12-88) Page 123.24
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
In the course of its business, the Company becomes involved in varous clais, contrversies, disputes and other contingent matters,
including the items described in this Note. Some of these claims, controversies, disputes and other contingent mattrs involve
litigation or other contested proceedings. For these proceedings, the Company intends to vigorously protect and defend its interests
and pursue its rights. However, no assurance can be given as to the ultiate outcome of any parcular matter because litigation and
other contested proceedings are inerently subject to numerous uncertties. For matters that afect A vist Corp.' s operaions, the
Company intends to seek, to the extent appropriate, recovery of incured costs though the ratemakg process.
Federal Energy Regulatory Commission Inquiry
In April 2004, the Federal Energy Regulatory Commission (FERC) approved the contested Agreement in Resolution of Section 206
Proceeding (Agreement in Resolution) between Avista Corp., Avista Energy and the FERC's Trial Staffwhich stated that there was:
(1) no evidence that any executives or employees of Avista Corp. or Avista Energy knowingly engaged in or faciltated any improper
trading strategy durg 2000 and 2001; (2) no evidence that Avista Corp. or Avista Energy engaged in any efforts to manpulate the
western energy markets durg 2000 and 2001; and (3) no fiding that Avista Corp. or A vista Energy witheld relevant inormation
from the FERC's inquir into the western energy markets for 2000 and 2001 (Tradg Investigation). The Attorney General of the
State of California (California AG), the California Electrcity Oversight Board, Californa Pares and the City of Tacoma, Washington
challenged the FERC's decisions approving the' Agreement in Resolution, which are now pending before the United States Cour of
Appeals for the Ninth Circuit (Ninth Circuit).
In May 2004, the FERC provided notice that Avista Energy was no longer subject to an investigation reviewing cert bids above
$250 per MW in the short-term energy markets operated by the California Independent System Operator (CanSO) and the California
Power Exchange (CalX) from May 1,2000 to October 2,2000 (Bidding Investigation). That matter is also pendig before the Ninth
Circuit, aftr the Californa AG, Pacific Gas & Electrc (pG&E), Soutern California Edison Company (SCE) and the California
Public Utilities Commission (CPUC) fied petitions for review in 2005.
Based on the FERC's order approvig the Agreement in Resolution and the FERC's denial of rehearg requests, the Company does
not expect that this proceeding wil have any material adverse effect on its fiancial condition, results of operations or cash flows.
Furermore, based on information curently known to the Company regarding the Bidding Investigation and the fact that the FERC
Staff did not fmd any evidence of manipulative behavior, the Company does not expect that this matter wil have a material adverse
effect on its fiancial condition, results of operations or cash flows. The Company has not accrued a liabilit related to this matter.
California Refund Proceeding
In July 2001, the FERC ordered an evidentiar hearg to determine the amount of refuds due to Californa energy buyers for
purchases made in the spot markets operated by the CanSO and the CalPX durg the period from October 2,2000 to June 20, 2001
(Refud Period). Proposed refuds are based on the calculation of mitigated market clear prices for each hour. The FERC ruled
that if the refuds required by the formula would cause a seller to recover less than its actual costs for the Refud Period, sellers may
document these costs and limit their refud liabilty commensurately. In September 20051 Avista Energy submitted its cost filing claim
pursuat to the FERC's Augut 2005 order. That filing was accepted in orders issued by the FERC in Januar 2006 and November
2006. In June 2009, the FERC reversed, in par its previous decision and ordered a compliance fiing requirg an adjustment to the
retu on investent component of Avista Energy's cost fiing. That compliance fiing was made in July 2009.
The CanSO continues to work on its compliance filing for the Refud Period, which wil show "who owes what to whom." In May
2009, the CanSO filed its 43rd status report on the California recalculation process confirg that the preparatory and the FERC
refud recalculations are complete (as are calculations related to fuel cost allowance offsets, emission offsets, cost-recovery offsets,
and the majority of the interest calculations). Once the FERC rues on several open issues, the CanSO states that it intends to: (1)
perform the necessar adjustment to remove refuds associated with non-jurisdictional entities and allocate that shortall to net refud
recipients; and (2) work with the pares to the varous global settements to make appropriate adjustments to the CanSO's data in
order to properly reflect those adjustments. After completig these calculations, the CalSO states that it intends to make a compliance
filing with the FERC that presents the fial fiancial position of each par that parcipated in its markets durg the Refud Period.
The 2001 banptcy of PG&E resulted in a default on its payment obligations to the CalPX. As a result, A vist Energy has not been
paid for all of its energy sales during the Refund Period. Those fuds are now in escrow accounts and will not be released until the
FERC issues an order directing such release in the Californa refud proceeding. As of December 3 i, 2009, A vista Energy's accounts
receivable outstading related to defaulting paries in California were fully offet by reserves for uncollected amounts and fuds
collected from defaulting paries.
I FERC FORM NO.1 (ED. 12-88)Page 123.25
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corporation í2) A Resubmission 0411612010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Many of the orders tht the FERC has issued in the Calornia refud proceedings were appealed to the Ninth Circuit. In October
2004, the Ninth Circuit ordered that bnefig proceed in two rounds. The fist round was limited to thee issues: (1) which paries are
subject to the FERC's refud jursdiction in light of the exemption for governent-owned utilties in section 201(f) of the Federal
Power Act (FPA); (2) the temporal scope of refuds under section 206 of the FPA; and (3) which categones of tranactions are subject
to refuds. The second round of issues and their correspondig bnefig schedules have not yet been set by the Ninth Circuit.
In September 2005, the Ninth Circuit held tht the FERC did not have the authonty to order refuds for sales made by muncipal
utilties in the Californa refud proceeding. In Augut 2006, the Ninth Circuit upheld October 2, 2000 as the refud effective date for
the FPA section 206 refud proceedig, but remaded to the FERC its decision not to consider an FPA section 309 remedy for taiff
violations prior to that date. Petitions for rehearg were denied in Apro 2009. In July 2009, A vista Energy and A vista Corp. filed a
motion at the FERC, askig that the companes be dissed from any fuer proceedis arsing under section 309 pursuant to the
remand. The filing pointed out tht section 309 relief is based on taff violations of the seller, and as to A vista Energy and A vista
Corp., these allegations had aleady been fuy adjudicated in the proceeding tht gave nse to the Agreement in Resolution, discussed
above. There, the FERC absolved both companies of all allegations of market manipulation or wrongdoing that would justify or
pennit FPA sections 206 or 309 remedies during 2000 and 2001. In November 2009, the FERC issued an order estblisg an
evidentiar hearg before an administrtive law judge to address the issues remanded by the Ninth Circuit without addressing the
Company's pending motion. In December 2009, the Company agai brougt the issue to the FERC's attention but its motion remain
pending.
Because the resolution of the Californa refud proceeding remais uncertin, legal counel canot express an opinion on the extent of
the Company's liabilty, ifany. However, based on infonnation curently known, the Company does not expect that the refuds
ultimately ordered for the Refud Period wil have a matena adverse effect on its fiancial condition, results of opertions or cash
flows. This is priarly due to the fact tht the FERC orders have stated tht any refuds wil be nettd againt unpaid amounts owed
to the respective pares and the Company does not believe that refuds would exceed unpaid amounts owed to the Company. As such,
the Company ha not accrued a liabilty related to ths mattr.
Pacific Northwest Refund Proceeding
In July 200 i, the FERC initiated a prelimar evidentiar hearg to develop a factu record as to whether prices for spot market
sales of wholesale energy in the Pacific Nortwest between December 25,2000 and June 20, 2001 were just and reasonable. In June
2003, the FERC tenninated the Pacifc Nortwest refud proceedings, aftr finding that the equities do not justify the imposition of
refuds. In August 2007, the Ninth Circuit found that the FERC, in denyig the request for refuds, had failed to tae into account
new evidence of market mapulation in the Californa energy market and its potential ties to the Pacific Nortwest energy market and
that such falure was arbitr and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's fidings must
be reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying
potential relief for transactions involving energy that was purchased by the Californa Deparent of Water Resources (CERS) in the
Pacific Nortwest and ultimately consumed in Californa. The Ninth Circuit expressly declined to direct the FERC to grt refuds.
Requests for rehearg were denied in April 2009.
In May 2009, the California AG filed a complaint againt both Avista Energy and Avista Corp. seekig refuds on sales made to
CERS durg the period Janua 18,2001 to June 20, 2001 under section 309 of the FPA (the Brown Complait). The sales at issue
are limited in scope and are duplicative of claim alady at issue in the Pacific Nortwest proceeding, discussed above. In Augut
2009, the City of Tacoma and the Port of Seattle fied a motion asking the FERC to sumarly re-pnce sales of energy in the Pacific
Nortwest durg 2000 and 2001. In October 2009, Avista Corp. filed, as par of the Tranaction Finality Group, an anwer to that
motion and in addition, made its own recommendations for fuer proceedings in this docket. Those pleadings are pending before the
FERC.
Both A vista Corp. and A vista Energy were buyers and sellers of energy in the Pacific Nortwest energy market durg the penod
between December 25, 2000 and June 20, 2001 and, if refuds were ordered by the FERC, could be liable to make payments, but alo
could be entitled to receive refuds from other FERC-jursdictional entities. The opportity to make clai againt non-jursdictiona
entities may be limted based on existig law. The Company canot predict the outcome of this proceeding or the amount of any
refuds that Avista Corp. or Avista Energy could be ordered to mae or could be entitled to receive. Therefore, the Company canot
predict the potential impact the outcome of ths mattr could ultimtely have on the Company's results of operations, fiancial
condition or cash flows. The Company has not accrued a liabilty related to ths matter.
California Attorney General Complaint (the "Lockyer Complaint'')
IFERC FORM NO.1 (ED. 12-88) Page 123.26
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
In May 2002, the FERC conditionally dismised a complaint fied in March 2002 by the California AG that alleged violations of the
FPA by the FERC and all sellers (including Avista Corp. and its subsidiares) of electrc power and energy into California. The
complait alleged that the FERC's adoption and implementation of market-based rate authority was flawed and, as a result, individual
sellers should refud the difference between the rate charged and a just and reasonable rate. In May 2002, the FERC issued an order
dismissing the complaint but directing sellers to re-fie certin trsaction sumares. It was not clear that Avist Corp. and its
subsidiares were subject to this directive but the Company took the conservative approach and re-fied certin tranaction sumaries
in June and July of2002. In September 2004, the Ninth Circuit upheld the FERC's market-based rate authority, but held tht the
FERC erred in ruling that it lacked authority to order refuds for violations of its reporting requirement. The Cour remanded the case
for fuer proceedings, but did not order any refuds, leaving it to the FERC to consider appropriate remedial options.
In March 2008, the FERC issued an order establishing a tral-tye hearg to address ''whether any individual public utlity seller's
violation of the FERC's market-based rate quaerly reportng requirement led to an unjust and uneasonable rate for that paricular
seller in California during the 2000-2001 period." Purchasers in the California markets will be allowed to present evidence that "any
seller that violated the quarerly reportg requirement failed to disclose an increased market share suffcient to give it the abilty to
exercise market power and thus cause its market-based rates to be unjust and unreasonable." In paricular, the pares are directed to
address whether the seller at any point reached a 20 percent generation market share theshold, and if the seller did reach a 20 percent
market share, whether other factors were present to indicate that the seller did not have the abilty to exercise market power. The
California AG, CPUC, PG&E, and SCE filed their testimony in July 2009. Avista Energy's anwerig testimony was filed in
. September 2009. On the same day, the FERC staff fied its answeri testony taing the position that, using the test the FERC
diected to be applied in this proceeding, A vista Energy does not have market power. Cross anwerig testiony and rebuttal
testiony were fied in November 2009. A hearg is expected to commence in April 2010.
Based on inormation curently laown to the Company's mangement and the fact that neither A vista Corp. nor Avista Energy ever
reached a 20 percent generation market share durg 2000 or 2001, the Company does not expect that ths matter will have a material
adverse effect on its fiancial condition, results of operations or cash flows. The Company has not accrued any liabilty related to ths
matter.
Colstrip Generating Project Complaints
In Marh 2007, two familes that own propert near the holding ponds from Units 3 & 4 of the Colstrp Generating Project (Colstrp)
filed a complaint against the owners of Colstrp and Hydrometrcs, Inc. in Montaa District Cour. A vista Corp. owns a 15 percent
interest in Units 3 & 4 of Colstrp. The plaintiffs allege that the holding ponds and remediation activities have adversely impacted
their propert. They allege containation, decrease in water tables, reduced flow of streams on their propert and other simlar
impacts to their propert. They also seek punitive damages, attorney's fees, an order by the cour to remove certin ponds, and the
forfeitue of profits eared from the generation of Colstrp. The tral is set to begin in May 2011. Because the resolution of this
complaint remain uncertain, legal counsel canot express an opinion on the extent, if any, of the Company's liabilty. However, based
on information curently Imown to the Company's management, the Company does not expect this complaint will have a material
adverse effect on its fiancial condition, results of operations or cash flows. The Company has Dot accned a liabilty related to this
matter.
Harbor Oillne. Site
Avista Corp. used Haror Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early
1 990s. In June 2005, the Environmental Protection Agency (EPA) Region i 0 provided notification to A vista Corp. and several other
pares, as customers of Haror Oil, that the EPA had determined that hazdous substaces were released at the Harbor Oil site in
Portland, Oregon and that Avista Corp. and severa other paries may be liable for investigation and cleanup of the site under the
Comprehensive Environmental Response, Compensation, and Liabilty Act commonly referred to as the federal "Superfd" law,
which provides for joint and severa liabilty. The iItial indication from the EPA is that the site may be containated with PCBs,
petroleum hydrocarbons, chlorinated solvents and heavy metas. Six potentially responsible pares, includig A vita Corp., signed an
Admstrative Order on Consent with the EPA on May 3 i, 2007 to conduct a remedial investigation and feasibilty stdy (RIS).
The tota cost of the RIS is estimated to be $1.5 milion and it is expected that it will be completed by early 20 i i. The actual
cleanup, ifany, wil not occur until the RIS is complete. Based on the review of its records related to Harbor Oil, the Company does
not believe it is a major contributor to this potential envionmental containation based on the small volume of waste oil it delivered to
the Harbor Oil site. However, there is curently not enough information to allow the Company to assess the probabilty or amount of a
liabilty, ¡fany, being incured. Other than its share of the RIS, the Company has not accrued a liabilty related to this matter.
Lake Coeur d'Alene
I FERC FORM NO.1 (ED. 12-88)Page 123.27
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Onginal (Mo, Da, Yr)
Avista Corporation 1(2) . A Resubmission 041612010 2009/04
NOTES TO FINACIA STATEMENTS (Continued)
In July 1998, the United States Distct Cour for the Distrct of Idao issued its fidig that the Coeur d'Alene Tribe (the Tribe) own,
among other things, portions of the bed and ban of Lake Coeur d'Alene (Lake) lyig within the curent boundares of the Tribe's
reservation lands. The United States Distrct Cour decision was afed by the United States Cour of Appeals for the Ninth Circuit
and the United States Supreme Cour in June 2001. This ownership decision resulted in, among other thgs, Avista Corp. being liable
to the Tribe for water storage on the Tribe's land and for the use of the Tribe's reservation lands under Section 10(e) of the Federal
Power Act (Section 10(e) payments). The Company's Post Falls Hydroelectrc Generatig Station (Post Falls) controls the water level
in the Lake for portions of the year (including portions of the lakebed owned by the Tribe).
In December 2008, Avista Corp., the Tribe and the United States Deparent of Interior (DOl) fialized an ageement regarding a
range of issues related to Post Falls and the Lake. The agreement establishes the amount of past and futue compensation Avista Corp.
will pay for Section 10(e) payments and issues related to licensing of the Company's hydroelectrc generating facilties located on the
Spokae River (see Spokane River Licensing below).
Avista Corp. ageed to compensate the Tribe a tota of$39 millon ($25 millon paid in 2008, $10 millon paid in 2009 and $4 milion
. to be paid in 2010) for trespass and Section 1 O( e) payments for past storage of water for the period from 1907 though 2007. A vista
Corp. agreed to compensate the Tribe for futue storage of wate though Section 1 O( e) payments of $0.4 millon per year begining in
2008 and contiuing though the firt 20 years of the new license and $0.7 milion per year though the remaining term of the license.
In addition to Section 1 O( e) payments, A vista Corp. agreed to mae anual payments over the life of the new FERC license to fud a
variety of protection, mitigation and enhancement measures on the Coeur d'Alene Reservation requied under Section 4( e) of the
Federal Power Act. These payments involve creation of a Coeur d'Alene Reservation Trut Restoration Fund (the Trut Fund).
Anual payments from the Company to the Trut Fund for protection, mitigation and enhancement measurements commenced with the
issuace of the new FERC license in June 2009 and tota $ 1 00 millon over the 50-year licene term.
The WUTC and IPUC approved deferr and fue recovery of amounts paid to the Tribe and the Trust Fund though general ra
cases in 2009.
On Janua 27, 2009, the Public Counel Section of the Washigton Attorney General's Offce (public Counel) fied a Petition for
Judicial Review (in Thurston County Superior Cour) of the WUC's December 2008 order approving the Company's general rate
case settlement. Public Counsel raised a number of issues that were previously argued before the WUTC. These include whether the
recovery of settlement costs associated with resolving the dispute with the Tribe would constitute ilegal "retroactive ratemakg" (the
Washington porton of these costs was $25.2 millon). Public Counel also questioned whether the WUTC's decision to ent~rtin
supplementa testiony to update the Company's filing for power supply costs durg the course of the proceedigs was appropriate.
Finlly, Pulic Counel argued that the settlement improperly included advertsing costs, dues and donations, and cert other
expenses. The appeal itself did not prevent the new rates from goin into effect.
On December 18,2009, the Thurston County Superior Cour afed the decision of the WUTC and rejected the arguents of Public
Counse~ with the exception of disallowing $0.1 miion of miscellaneous expenses, including chartable donations. Public Counel ha
until March 4, 2010 to fuer appeal the WUC's decision.
Spokane River Licensing
The Company own and operates six hydroelectric plants on the Spokae River. Five of these (Long Lake, Nine Mile, Upper Falls,
Monroe Street, and Post Falls, which have a total present capabilty of 144.l MW) are under one FERC license and are referred to as
the Spokane River Project. The six Little Falls, is operated under separate Congressional authority and is not licensed by the FERC.
The FERC issued a new single 50-year license for the Spokae River Project on June 18, 2009.
The license incorporated the 4( e) conditions that were included in the December 2008 Settement Agreement with the DOl and the
Tribe, as well as the mandaory conditions that were agreed to in the Idao 401 Water Quaity Certfications and in the amended
Washigton 401 Water Quity Certfication. Varous issues that were appealed under the Wason 401 Water Qualty
Certification were subsequently resolved though settlement.
As par of the Settlement Agreement with the Washigtn Deparent of Ecology (DOE), the Company is curently engaged with the
DOE and the EPA Total Maximum Daily Load (TL) process for the Spokae River and Lake Spokane, the reservoir created by
Long Lake Dam. On Febru 12,2010, the DOE submitted the TMDL for the EPA's review and approvaL. Once the TML process
is completed, and the Company's level of responsibilty related to low dissolved oxygen in Lake Spokane is established, the Company
will identifY potential mitigation measures. It is not possible to provide cost estimates at this tie because the mitigation measures
IFERC FORM NO.1 (ED. 12-88) Page 123.28
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1)~An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
have not been fully indentified or approved by the DOE. It is also possible the TMDL will be appealed by one or more pares if it is
approved by the EPA.
The Company has begu implementing the environmental and operational conditions required in the license for the Spokane River
Project. The estimated cost to implement the license conditions for the five hydroelectrc plants is $334 milion over the 50 year
license term. This wil increase the Spokane River Project's cost of power by about 40 percent, while decreasing anual generation by
approximately one-half of one percent. Costs to implement mitigation measures related to the TML are not included in these cost
estiates.
The IPUC and the WUC approved the recovery of licensing costs though the general rate case settlements in 2009. The Company
wil contiue to seek recovery, though the ratemakg process, of all operatig and capitalized costs related to the licensing of the
Spokae River Project.
Clark Fork Setement Agreement
Dissolved atmospheric gas levels in the Clark Fork River exceed state of Idaho and federa water quality stadards downstream of the
Cabinet Gorge Hydroelectrc Generating Project (Cabinet Gorge) durg periods when excess river flows must be diverted over the
spilway. In 2002, the Company submittd a Gas Supersatuation Control Program ("GSCP") with the Idao Deparent of
Environmental Quality (Idaho DEQ) and U.S. Fish and Wildlife Service (USFWS). This submission was par of the Clar Fork
Settlement Agreement for licensing the use of Cabinet Gorge. The GSCP provides for the opening and modification of possibly two
diversion tuels around Cabinet Gorge to allow streamflow to be diverted when flows are in excess of powerhouse capacity. In 2007,
engineering studies determined that the tuels would not sufciently reduce Total Dissolved Gas (TOG). In consultation with the
Idaho DEQ and the USFWS, the Company developed addendum to the GSCP. The GSCP addendum abandons the existing concept to
reopen the two diversion tuels and requies the Company to evaluate a varety of smaller capacity options to abate TOG over the
next several years. The addendum was filed with the FERC in October 2009 and is pending approvaL.
In 1999, the USFWS listed bull trout as theatened under the Endangered Species Act. The Clark Fork Settlement Agreement
describes progr intended to restore bull trout populations in the project area. Using the concept of adaptive management and
working closely with the USFWS, the Company is evaluatin the feasibilty offish passage at Cabinet Gorge and Noxon Rapids. The
results of these studies wil help the Company and other pares determe the best use of fuds toward continuing fish passage efforts
or other bull trut population enhancement measures. In the fall of 2009 the Company initiated a contractor selection process for the
design of a permanent upstrea passage facilty at Cabinet Gorge. On Januar 13,2010, the USFWS proposed to revise its 2005
designation of crtical habitat for the bull trout. The proposed revisions include the lower Clark Fork River as critical habitat. The
USFWS is accepting public comment on the proposed revisions until March 15,2010. The Company is reviewing the proposed
revisions.
Air Qualit
The Company must be in compliance with requirements under the Clean Air Act and Clean Air Act Amendments for its thermal
generating plants. The Company continues to monitor legislative developments at both the state and national level for the potential of
fuer restrctions on sulfu dioxide, nitrogen oxide and carbon dioxide, as well as other greenhouse gas and mercur emissions.
In 2006, the Montaa Deparent of Environmental Quality (Montaa DEQ) adopted fial rules for the control of mercur emissions
from coal-fied plants. The new rules set strct mercur emission limits by 2010, and put in place a recurg ten-year review process
to ensure facilties are keeping pace with advancing technology in mercu emission control. The rues also provide for tempora
alternate emission limits provided certin provisions are met, and they allocate mercur emission credits in a maner that rewards the
cleanest facilties.
. Compliance with new and proposed requiements and possible additional legislation or regulations results in increases to capital
expenditues and operating expenses for expanded emission controls at the Company's thermal generating facilties. The Company,
along with the other owners of Colstrp, completed the first phase of testig on two mercur control technologies. The joint owners of
Colstrp believe, based upon curent results, that the plant will be able to comply with the Monta law without utilizing the tempora
alternate emission limit provision. Curent estiates indicate that the Company's share of installation capital costs will be $1.4 milion
and anual operatig costs will increase by $1.5 milion (began in late-2009). The Company wil continue to seek recovery, though
the ratemaking process, of the costs to comply with varous air quality requirements.
Aluminum Recycling Site
In October 2009, the Company (though its subsidiar Pentzr Corporation) received notice from the DOE proposing to find Pentzr
IFERC FORM NO.1 (ED. 12-88) Page 123.29
Name of Respondent This Report is:Date of Report Year/Penod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation 1(2) . A Resubmission 041612010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
liable for a release of hazdous substaces under the Model Toxics Control Act (MTCA), under Washigton sta law. The subject
propert adjoin land owned by the Union Pacific Ralroad (UR). UPR leased their propert to operators of a facilty designated by
DOE as "Aluminum Recyclig - Trentwood." Operators of that proper mataed piles of alumum "black dross," which can be
designated as a state-only dangerous waste in Washigtn State. Operators placed a portion of the aluminum dross pile on the site
owned by Pentzr Corpration. The Company does not believe it is a contrbutor to any environmental containtion associated with
the dross pile, and submitted a response to the DOE's proposed fidings in November 2009. In December 2009, the Company
received notice from the DOE tht it had been designated 'as a potentially liable par for any hazdous substaces located on ths site.
There is curently not enough inormation to allow the Company to assess the probabilty or amount of a liabilty, if any, being
incured. The Company has not accrued a liabilty related to ths mattr.
Collective Bargaining Agreements
As of December 31,2009, the Company's collective bargaing agreement with the International Brotherhood of Electrcal Workers
represented approximately 45 percent of all of Avista Corp.'s employees. The agreement with the local union in Washigton and
Idao representig the majonty (approxiately 90 percent) of the bargaiing unit employees expires on March 26, 2010. Two local
agreements in Oregon, which cover approximtely 50 employees, expire in April 2010. Negotiations are curently ongoing for these
labor agreements.
Other Contingencies
In the normal course of business, the Company has varous other legal clais and contingent matters outstading. The Company
believes that any ultimate liabilty arsing from these actions wil not have a matenal adverse impact on its financial condition, results
of operations or cash flows. It is possible that a chage could occur in the Company's estimates of the probabilty or amount ofa
liabilty being incured. Such a change, should it occur, could be signcant.
The Company routiely assesses, based on in-depth studies, expert analyses and legal reviews, its contingencies, obligations and
commitments for remediation of contaated sites, including assessments of rages and probabilties of recovenes from other
responsible paries who have and have not agreed to a settement and recoveres from insurance carers. The Company's policy is to
accrue and charge to curent expense identified exposures related to envionmental remediation sites based on estiates of
investigation, cleanup and monitorig costs to be incured.
The Company has potential liabilties under the Endangered Species Act for species of fish that have either aleady been added to the
endangered species list, been listed as "theatened" or been petitioned for listing. Thus far, measures adopted and implemented have
had minal impact on the Company.
Under the federal licenses for its hydroelectrc projects, the Company is obligated to protect its propert rights, including water nghts.
The state of Montaa is examing the statu of all water right clai within state boundares. Claim within the Clark Fork River
basin could potentially adversely affect the energy production of the Company's Cabinet Gorge and Noxon Rapids hydroelectrc
facilties. The state ofIdaho is conductig an adjudication in nortern Idaho, which wil ultimtely include both the lower Clark Fork
River, the Spokae River and the Coeur d'Alene basin. In addition, the state of Washington has indicated its intent to initiate an
adjudication for the Spokae River basin in the next several years. The Company is parcipatig in these extensive adjudication
processes, which are unlikely to be concluded in the foreseeable futue.
NOTE 23. INFORMATION SERVICES CONTRACTS
The Company has information services contracts tht expire at varous times though 2012. Tota payments under these contracts were
$15.5 milion in 2009 and $15.4 milion in 2008. The majonty of the cost are included in operation expenses in the Staements of
Income. Minum contracl obligations under the Company's inormtion servces contrts are $13.2 millon in 2010, $12.9
milion in 201 1, and $12.2 millon in 2012. The largest of these contrts provides for increases due to changes in the cost of livig
index and fuer provides flexibilty in the anual obligation from year-to-year subject to a thee-year tre-up cycle.
NOTE '24. REGULATORY MATTERS
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge on the Balance Sheets for futue review and recovery though retail
rates. The power supply costs deferred include cert differences between actul net power supply costs incurd by A vista Corp. and
the costs included in base reta rates. This difference in net power supply costs pnmarly results from changes in:
. short-term wholesale maket pnces and sales and purchase volumes,
IFERC FORM NO.1 (ED. 12-88) Page 123.30
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation 1(2) . A Resubmission 04116/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
. the level of hydroelectc generation,
· the level ofthennal generation (including changes in fuel prices), and
. retail loads.
In Washington, the ERM allows Avista Corp. to periodically increase or decrease electric rates with WUTC approval to reflect
changes in power supply costs. The ERM is an accounting method used to track certain differences between actual net power supply
costs and the amount included in base retail rates for Washigton customers. The Company must make a fiing (no sooner than
Janua 1, 201 I), to allow all interested paries the opportity to review the ERM, and make recommendations to the WUC related
to the continuation, modification or elimination of the ERM.
The initial amount of power supply costs in excess or below the level in retail rates, which the Company either incur the cost of, or
receives the benefit from, is referred to as the deadband. The anual (calenda year) deadband amount is curently $4.0 milion. The
Company wil incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost varance. The Company
shares anual power supply cost varances between $4.0 milion and $10.0 milion with its customers. There is a 50 percent
customers/50 percent Company sharg when actul power supply expenses are higher (surcharge to customers) than the amount
included in base retail rates within this band. There is a 75 percent customers/5 percent Company sharg when actul power supply
expenses are lower (rebate to customers) than the amount included in base retal rates with this band. To the extent that the anual
power supply cost varance from the amount included in base rates exceeds $ i 0.0 milion, 90 percent of the cost varance is deferred
for futue surcharge or rebate. The Company absorbs or receives the benefit in power supply costs of the remaing 10 percent of the
anual variance beyond $10.0 milion without affecting curent or futue customer rates. The followig is a sumar of the ERM:
Deferred for Futue
Surcharge or Rebate
to Customers
0%
50%
75%
90%
Anual Power Supply
Cost Varabilty
+/- $0 - $4 milion
+ between $4 milion - $ 10 milion
- between $4 millon - $ 1 0 milion
+1- excess over $10 milion
Expense or Benefit
to the Company
100%
50%
25%
10%
A vista Corp. has a PCA mechanism in Idaho that allows it to modify electrc rates on Octber 1 of each year with Idaho Public
Utilities Commission (IUC) approvaL. Under the PCA mechansm, Avista Corp. defers 90 percent of the difference between certin
actal net power supply expenses and the amount included in base retail rates for its Idaho customers. In June 2007, the IPUC
approved continuation of the PCA mechanism with an anua rate adjustment provision. These anual October 1 rate adjustments
recover or rebate power costs deferred during the preceding July-June twelve-month period.
The following table shows activity in deferred power costs for Washington and Idao durg 2008 and 2009 (dollars in thousands):Washigton Idaho Total
Deferred power costs as of Decemb.er 31, 2007 $58,524 $21,163 $79,687
Activity from Januar 1 -December 31,2008:
Power costs deferred
Interest and other net additions
Recovery of deferred power costs though retail rates
Deferred power costs as of December 3 I, 2008
Actvity from Janua 1 - December 31,2009:
Power costs deferred
Interest and other net additions
Recovery of deferred power costs though retal rates
Deferred power costs as of December 31, 2009
In Febru 2010, the WUTC approved the Company's request to eliminate the existing ERM surharge. The surhage was
eliminated because the previous balance of deferred power costs has been substatially recovered. This will result in an overall rate
reduction of 7 percent for the Company's Washington customers with no impact on income from operations or net income.
7,049 10,029 17,078
2,231 1,153 3,384
(30,852)01.690)(42.542)
36,952 $20,655 57,607
17,985 17,985
879 388 1,267
(31.67)07,521)(49,088)
$6264 $2~,507 $27,771
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Corp. fies a purchased gas cost adjustment (pGA) in all thee states it serves to adjust natual gas rates for: 1) estimated
commodity and pipeline tranporttion costs to serve natu gas customers for the coming year, and 2) the difference between actual
IFERC FORM NO.1 (ED. 12-88) Page 123.31
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 041612010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
and estimated commodity and trsporttion costs for the prior year. These anua PGA fiings in Wasgton and Idao provide for
the deferral, and recovery or refud, of 100 percent of the difference between actu and estimat commodity and pipelie
transporttion costs for the prior year, subject to applicable reguatory review. The anual PGA fiing in Oregon provides for deferral,
and recovery or refud, of i 00 percent of the difference between actul and estimated pipeline tranportation costs and commodity
costs that are fixed though hedge transactions. Commodity costs th are not hedged for Oregon customers are subject to a shag
mechansm whereby A vista Corp. defers, and recovers or refuds, 90 percent of the difference between these actual and estimated
costs. Total net deferred natual gas costs to be refuded to customers were a liabilty of $40.0 millon as of December 3 i, 2009 and
$18.6 milion as of December 31, 2008.
General Rate Cases
The followig is a sumar of the Company's authorid rates of retu in each jursdiction:
Jurisdiction and service
Washington electrc and natual gas
Idaho electrc and natual gas
Oregon natual gas
Implementation
Date
Januar 2010
August 2009
November 2009
Authorid
Overall Rate
of Retu
8.25%
8.55%
8.19%
Authorid
Retu on
Equity
10.2%
10.5%
10.1%
Authoried
Equity
Level
46.5%
50.0%
50.0%
Washington General Rate Cases
As approved by the WUTC, on Januar 1,2008, electrc rates for the Company's Washington customers increased by an average of
9.4 percent, which was designed to increae anua revenues by $30.2 milion. As par of ths general rate increase, the base level of
power supply costs used in the ERM calculations was updated Also, on Janua 1,2008, natu gas rates increased by an average of
1.7 percent, which was designed to increae anua revenues by $3.3 millon.
In September 2008, Avista Corp. entered into a settement stipulation in its general rate case that was filed with the WUC in March
2008. This settement stipulation was approved by the WUTC in December 2008. The new electric and natual gas rates became
effective on Janua 1,2009. As agreed to in the settement, base electc rates for the Company's Washington customers increased by
an average of9.l percent, which was designed to increase anual revenues by $32.5 millon. Base natual gas rates for the Company's
Wasington customers increased by an average of2.4 percent, which was designed to increase anual revenues by $4.8 milion.
On Janua 27,2009, Public Counsel fied a Petition for Judicial Review (in Thurston County Superior Cour) of the WUTC's
December 2008 order approving Avist Corp.' s multipar settlement. Public Counel rased a nwnber of issues that were previously
argued before the WUTC. These included whether the recovery of settlement costs associated with resolvig the dispute with the
Coeur d'Alene Tribe would constitue ilegal ''retroactive ratemag" (the Washigton portion of these costs was $25.2 millon).
Public Counsel also questioned whether the WUTC's decision to entert supplemental testiony by the Company to update its fiing
for power supply costs durg the coure of the proceedings was appropriate. Finlly, Public Counsel argued that the settlement
improperly included advertising costs, dues and donations,. and certin other expenses. The appeal itself did not prevent the new rates
from going into effect.
On December 18,2009, the Thurston County Superior Cour afined the decision of the WUTC and rejected the arguents of Public
Counel, with the exception of disallowing $0.1 milion of miscellaneous expenses, including chartable donations. Public Counel has
until Marh 4, 2010 to fuer appeal the WUC's decision.
On December 22,2009, the WUTC issued an order on Avista Corp.'s electrc and natual gas rate general rate cases that were fied
with the WUTC in Janua 2009. The WUTC approved a base electrc rate increase for the Company's Washigton customers of2.8
percent, which is designed to increase anual revenues by $12.1 millon. Base natual gas rates for the Company's Washigton
customers increased by an average of 0.3 percent, which is designed to increase anual revenues by $0.6 miion. The new electrc and
natual gas rates becae effective on Janua 1,2010.
Following the execution of a parial settement stipulation in September 2009, A vita Corp. revied downward its electrc rate increae
request from $69.8 millon to $37.5 millon, prily due to the declie in the wholesale prices ofeleeticity and natual gas. Avista
Corp. also reduced its natual gas request from $4.9 milion to $2.8 milion. Under the parial settlement stipulaton, the Company
reached agreement with the other settling paries on issues in the areas of cost of capital, power supply, rate spread and rate design and
fudig under the Low-Income Ratepayer Assistace Progr The WUTC approved this parl settlement stipulation in its order on
December 22, 2009.
IFERC FORM NO.1 (ED. 12-88) Page 123.32
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Oa, Yr)
Avista Corporation (2) A Resubmission 04/16/2010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The WUC did not allow Avista Corp. to include the costs associated with the power purchase agreement for the Lancaster Plant in
rates, indicating the Company did not demonstrate compli~ce with certin requirements necessar for imediate inclusion in rates.
However, the WUTC directed A vista Corp. to fie to defer costs associated with the Lancaster Plant, with a caring charge, for
potential recovery in a futue rate proceeding if the Company demonstrates that it has satisfied these requirements. The Company's
proposed deferred accountig treatment for the net costs associated with the Lancaster Plant was approved by the WUTC in Februar
2010. The net costs associated with the power purchase agreement for the Lancaster Plant account for approximately half of the
diference between the Company's revised electrc rate increase request of$37.5 milion and the $12.1 millon increase approved by
theWUTC.
The WUC also did not allow for certin pro forma futue capital additions to rate base, as well as cert increases in labor costs, tree
trin costs and information systems costs. These costs account for the majority of the remaiing difference between the
Company's revised electrc rate increase request and the amount approved by the WUTC.
The pariai settlement stipulation (as approved by the WUTC on December 22, 2009) is based on an overll rate of retu of 8.25
percent with a common equity ratio of 46.5 percent and a 10.2 percent retu on equity. The Company's original request was based on
a proposed overall rate of retu of8.68 percent with a common equity ratio of 47.5 percent and an 11.0 percent retu on equity.
Idaho General Rate Cases
In Augut 2008, the Company entered into an all-par settlement stipulation in its general rate case tht was filed with the IPUC in
April 2008. This settlement stipulation was approved by the IPUC in September 2008. The new electric and natu gas rates became
effective on October 1,2008. As agreed to in the settement, base electric rates for the Company's Idaho customers increased by an
average of 12.0 percent, which was designed to increase anual revenues by $23.2 milion. Base natual ga rates for the Company's
Idao customers increased by an average of 4.7 percent, which was designed to increase anual revenues by $3.9 milion.
In June 2009, the Company entered into an all-par settement stipulation in its electc and natu gas genera rate cases that were
filed with the IPUC in Januar 2009. This settement stipulation was approved by the IPUC in July 2009. The new electrc and natual
gas rates became effective on Augut 1,2009. As agreed to in the settement, base electrc rates for the Company's Idao customers
increased by an average of 5.7 percent, which was designed to increase anual revenues by $ I 2.5 milion. Offsetting the base electrc
rate increase was an overall 4.2 percent decrease in the PCA surcharge, which was designed to decrease anual PCA revenues by $9.3
milion, resulting in a net increase in annual revenues of $3.2 milion. Base natul gas rates for the Company's Idao customers
increased by an average of 2. I percent, which was designed to increase anual revenues by $ I .9 milion. Offsetting the natual gas rate
increase for residential customers was an equivalent PGA decrease of2.1 percent. Lage general servces received a PGA decrease of
2.4 percent and interrptible servces received a PGA decrease of2.8 percent. The overall PGA decrease resulted in a $2.0 milion
decrease in anual PGA revenues, resulting in a net decrease in anual revenues of $0. i milion. The PGAs are designed to pass
though changes in natual gas costs to customers with no change in gross magin or net income.
Oregon General Rate Cases
As approved by the OPUC in March 2008, natual gas rates for the Company's Oregon customers increased 0.4 percent effective April
1,2008 (designed to increase anual revenues by $0.5 milion) and increased an additional 1. percent effective November i, 2008
(designed to increase anual revenues by an additional $1.4 milion).
In September 2009, the Company entered into an all-par settement stipulation in its general rate case that was fied with the OPUC
in June 2009. This settlement stipulation was approved by the OPUC in October 2009. The new natual gas rates became effective on
November 1,2009. As agreed to in the settlement, base natual gas rates for Oregon customers increased by an average of7.1 percent,
which is designed to increase anual revenues by $8.8 millon.
NOTE 25. SUPPLEMENTAL CASH FLOW INORMTION
(dollar in thousands)
Cash paid for interest
Cash paid for income taes
2009
$58,197
$22,695
2008
$76,434
$8,116
Oter Cash Flows from Operating Activities:
Power and natul gas deferrals
Change in special deposits
IFERC FORM NO.1 (ED. 12-88)
$(216)
$(30)
$(2,736)
$4,068
Page 123.33
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/1612010 2009/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Chage in other curent assets
Non-cash stock compensation
Gai on sale of assets
$(1,923)
$2,596
$(89)
$(2,149)
$2,541
$(1,123)
IFERC FORM NO.1 (ED. 12-88) Page 123.34
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A~ D HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accunted for as "fair value hedges", report the accunts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liabilty adjustment Hedges Adjustments
for-5ale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Accunt 219 at Beginning of
Preceding Year (12,781,264)
2 Preceding OtrNr to Date Reclassifications
from Acc 219 to Net Income
3 Preceding QuarterNear to Date Changes in
Fair Value 6,688,946
4 Total (lines 2 and 3)6,688,946
5 Balance of Accunt 219 at End of
Preceing QuarterNear (6,092,318)
6 Balance of Account 219 at Beginning of
Current Year (6,092,318)
7 Current OtrNr to Date Reclassifications
from Acct 219 to Net Income
8 Current OuarterNear to Date Changes in
Fair Value 3,742,032
9 Total (lines 7 and 8)3,742,032
10 Balance of Accunt 219 at End of Current
OuarterNear (2,350,286)
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612010
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A
YearlPeriod of Report
End of 2009/04
D HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Totals for each
category of items
recorded in
Accunt 219
(h)
( 19,607,486)
10,656,750
2,858,418
13,515,168
6,092,318)
6,092,318)
Other Cash Flow
Hedges
(Specify)
1
2
3
4
5
6
7
8
9
10
(f)
( 6,826,222)
10,656,750
3,830,528)
6,826,222
(g)
3,742,032
3,742,032
2,350,286)
Net Income (Carried
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
(i)ü)
FERC FORM NO.1 (NEW 06-02)Page 122b
a e 0 epo
(Mo, Da, Yr)
04/1612010
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (speci) and in
column (h) common function.
End of
(a)
Total Company for the
Currnt YeadOuarter Ended
(b)
Electric
(c)
Line
No.
Classification
Utilty Plant
2 In Service
3 Plant in Service (Classifed)
4 Propert Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utilty Plant (8 thru 12)
14 Accum Prov for Depr, Amort, & Depl
15 Net Utilty Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas LandlLand Right
20 Amort of Underground Storage LandlLand Rights
21 Amort of Other Utiit Plant
22 Total In Service (18 thru 21)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
3,520,534,663
1,903,329
2,678,537,207
3,522,437,992 2,678,537,207
1,631,351
57,217,478
22,122,748
3,603,409,569
1,219,877,922
2,383,531,647
1,457,302
42,232,962
2,722,227,471
917,624,851
1,804,602,620
20,490,275
1,219,877,922 917,624,851
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
Avista Corporation
Gas
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612010
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Other (Specify)
YearlPeriod of Report
End of 2009/04
Common Line
No.
688,622,700
1,619,845
153,374,756
283,484
690,242,545 153,658,240
174,049
4,524,629
22,122,748
717,063,971
258,391,573
458,672,398
10,459,887
164,118,127
43,861,498
120,256,629
20,490,275
258,391,573 43,861,498
FERC FORM NO.1 (ED. 12-89)Page 201
Name of Respondent This o0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) OOA Resubmission 05/121010
ELECTRI PLA IN SERVICE (Accunt 101, 102, 103 and 106)
1. Report below the original cost of electic plant in service accrding to the prescbed accunts.
2. In addition to Accunt 101, Electric Plant in Service (Classifed), this page and the next include Accunt 102, Electric Plant Purchased or Sold;
Accunt 103, Experimental Elecric Plant Unclassifed; and Acunt 106, Completed Construction Not Classifed-Electric.
3. Include in column (c) or (d), as appropriate, correctons of additions and reirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitlized, included by primary plant accunt, increases in column (c) additions and
reductons in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accunts to indicate the negatie effect of such accunts.
6. Classif Accunt 106 accrding to prescribed accunts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributons of prior year reported in column (b). Likewise, if the respondent has a signifcant amount
of plant retirements which have not been classifed to primary accunts at the end ofthe year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, wit appropriate contra entry to the accunt for accumulated depreciation provision. Include also in column (d)
ine Accunt ~No.(a)
Beginning of Year(b) c
1 1. INTANGIBLE PLANT
2 (301) Oraanization
3 (302) Franchises and Consents 15,629,982 28,848,313
4 (303) Miscellaneous Intanaible Plant 3,474,009 494,838
5 TOTAL Intanaible Plant (Enter Total of lines 2, 3, and 4)19,103,991 29,343,151
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Riahts 2,231,688
9 311) Strctures and Improvements 124,816,325 129,197
10 (312) Boiler Plant Eauipment 162,892,531 3,935,651
11 (313) Enaines and Engine-Driven Generators
12 (314) Turboaenerator Units 47,684,556 1,148,746
13 (315) Accssory Electric Equipment 26,371,619 564,179
14 316) Misc. Power Plant Equioment 15,474,936 191,965
15 317) Asset Retirement Costs for Steam Producton 585,276
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)380,056,931 5,969,738
17 B. Nuclear Production Plant
18 (320) Land and Land Riahts
19 (321) Strctures and Improvements
20 (322 Reactor Plant Eauioment
21 (323 Turbogenerator Unit
22 (324 Accssorv Electric Eauipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hl'draulic Production Plant
27 (330 Land and Land Rights 55,860,497 658,506
28 (331 Stuctures and Imoro"vements 39,908,000 765,660
29 (332 Reservoirs, Dams, and Waterwavs 117,490,242 306,076
30 i(333 Water Wheels, Turbines, and Generators 123,875,342 17,876,895
31 (334 Accssorv Electric Eauipment 31,487,985 2,708,041
32 ¡ (335) Misc. Power PLant Eauipment 6,288,495 1,117,996
33 (336) Roads, Railroads, and Bridaes 1,999,562
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)376,910,123 23,433,174
36 D. Oter Production Plant
37 (340) Land and Land Riahts 903,118
38 (341 Strctures and Improvements 15,617,416 125,824
39 (342 Fuel Holders, Product, and Accssories 21,064,681
40 (343 Prime Movers 21,876,780
41 (34) Generators 197,970,615 810,715
42 (345) Accssory Electric Eauioment 15,829,566 222,469
43 (346) Misc. Power Plant Equioment 1,344,105 45,317
44 (347) Asset Retirement Costs for Other Production 351,682
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)274,957,963 1,204,325
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)1,031,925,017 30,607,237
FERC FORM NO.1 (REV. 12-05)Page 204
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) UAn Original (Mo, Da, Yr)
(2) X A Resubmission 0511212010
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)
distributions of these tentative classifcations in columns (c) and (d), including the reversals of the prior years tentative accunt distributions of these
amounts. Careful observance of the above instructions and the text of Accunts 101 and 106 wil avoid senous omissions of the reported amount of
respondents plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers witin utilit plant accunts. Include also in column (f) the additions or reductions of primary accunt
classifcations arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts wih respect to accmulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offet to the debits or crdits distributed in column (f) to pnmary
accunt classifcations.
8. For Accunt 399, state the nature and use of plant included in this accunt and if substantial in amount submit a supplementary statement showing
subaccunt classifcation of such plant conforming to the requirement of these pages.
9. For each amount compnsing the reported balance and changes in Accunt 102, state the propert purchased or sold, name of vendor or purchase,
and date oftransaction. If proposed joumal entries have been filed with the Commission as required by the Uniform System of Accounts, give also dateRetirements Adjustments Transfers Balance at LineEnd rJ)Year No.
942
41,818
533,406
2,230,746
124,903,704
166,294,776
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
594,261
5,784
15,969
48,239,041
26,930,014
15,650,932
585,276
384,834,489
17,587
56,519,003
40,656,073
117,796,318
141,170,373
34,096,337
7,318,628
1,999,562
581,864
99,689
87,863
787,003 399,556,294
57,927
903,118
15,743,240
21,064,681
21,876,780
198,781,330
15,994,108
1,389,422
351,682
276,104,361
1,060,495,144
57,927
2,037,110
FERC FORM NO.1 (REV. 12-05)Page 205
Name of Respondent This (j0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) jîA Resubmission 05/1212010
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)
..ine Accunt ~No.(a)
Beginning of Year(b c
47 3. TRASMISSION PLANT
48 (350) Land and Land Richts 15,595,500 496,556
49 352) Structures and Improvements 15,750,369 290,386
50 353) Station Eauioment 172,929,491 6,687,685
51 354) Towers and Fixures 17,098,314 14,715
52 355) Poles and Fixures 128,285,893 3,424,336
53 (356) Overhead Conductors and Devices 103,930,504 2,428,936
54 357) Underaround Conduit 2,605,488
55 358) Underaround Conductors and Devices 2,330,071
56 359) Roads and Trails 1,872,246
57 359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)460,397,876 13,342,614
59 4. DISTRIBUTION PLANT
60 360) Land and Land Rights 4,068,189 267,938
61 (361) Strudures and Improvements
"12,262,082 1,767,765
62 362 Station Eauioment 86,204,015 7,460,205
63 1(363 Storace Batterv Eauipment
64 364 Poles, Towers, and Fixtures 196,776,445 17,752,502
65 365 Overhead Conductors and Devices 129,268,022 9,985,456
66 366 Underaround Conduit 71,349,434 3,517,231
67 367 Underaround Conductors and Devices 115,565,756 8,098,244
68 368 Line Transformers 159,545,964 12,119,967
69 369 Services 110,109,363 5,149,552
70 (370 Meters 44,273,042 1,673,893
71 371 Installations on Customer Premises
72 372 Leased Prooert on Customer Premises
73 373 Stret Liahtina and Sianal Svstems 27,761,029 1,687,359
74 (374) Asset Retirement Costs for Distribution Plant 129,707
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)957,313,048 69,480,112
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380 Land and Land Riahts
78 (381 Structures and Improvements
79 (382 Computer Hardware
80 (383) Computer Softare
81 (384) Communication EQuipment
82 (385) Miscllaneous Reaional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Ooeration Plant ITotallines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights 124,681
87 1 (390) Structres and Improvements 2,174,744 1,258,965
88 1 (391 Ofce Fumiture and EQuipment 718,653 445,016
89 1(392 Transoortation EQuipment 9,481,838 2,232,469
90 (393 Stores Eauipment 327,794 55,665
91 394 Tools, Shop and Garage EQuipment 3,353,108 101,947
92 395 Laboratorv Eauioment 1,389,374 78,186
93 396 Power Operated Eauipment 21,732,539 4,321,967
94 1397) Communication EQuipment 36,464,026 2,663,059
95 398) Miscllaneous Eauipment 2,781 6,068
96 SUBTOTAL (Enter Total of lines 86 thru 95)75,769,538 11,163,342
97 399) Other Tanaible Propert
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)75,769,538 11,163,342
100 TOTAL (Accunts 101 and 106)2,54,509,470 153,936,456
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electic Plant in Service (Enter Total of lines 100 thru 103)2,54,509,470 153,936,456
FERC FORM NO.1 (RE. 12-05)Page 206
Name of Respondent This (j0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) jXA Resubmission 0511212010
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)
Line~ e ro ~r~M No.
47
16,092,056 48
16,040,755 49
1,938,336 1n,678,840 50
17,113,029 51
98,793 131,611,436 52
17,544 106,341,896 53
2,605,488 54
2,330,071 55
1,872,246 56
57
2,054,673 471,685,817 58
59
4,336,127 60
14,029,847 61
465,752 93,198,468 62
63
226,413 214,302,534 64
244,866 139,008,612 65
50,249 74,816,416 66
508,367 123,155,633 67
2,091,011 169,574,920 68
76,668 115,182,247 69
939,786 45,007,149 70
71
72
105,899 29,342,489 73
129,707 74
4,709,011 1,022,084,149 75
76n
78
79
80
81
82
83
84
85
124,681 86
1,290 3,432,419 87
1,163,669 88
308,102 11,406,205 89
383,459 90
3,455,055 91
1,467,560 92
859,923 25,194,583 93
27,376 39,099,709 94
8,849 95
1,196,691 85,736,189 96
97
98
1,196,691 85,736,189 99
9,997,485 2,688,448,441 100
101
102
103
9,997,485 2,688,448,441 104
FERC FORM NO.1 (REV. 12-05)Page 207
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/1612010
EL CTRIC PLANT HELD FOR FUTURE USE (Accunt 105)
1. Report separately each propert held for future use at end of the year having an original cost of $250,000 or more. Group other items of propert held
for tutu re use.
2. For propert having an original cost of $250,000 or more previously used in utilit operations, now held for fuure use, give in column (a), in addition to
other required information, the date that utilit use of such propert was discontinued, and the date the original cost was transferre to Accunt 105.
Line Descnption and Location ~No.OfProlert in is Accunt in Utilit Service End of Year
(a (b) (c) (d)
1 Land and Rights:
2
3
4 Distribution Plant Land, Spokane, Washington Oct 2008 Unknown 1,457,302
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Other Propert:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 1,457,302
FERC FORM NO.1 (ED. 12-96)Page 214
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
CONSTRUCTION WORK IN PROGRESS - - ELEC TRIC (Accunt 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Accunt 107 ofthe Uniform System of Accounts)
3. Minor project (5% of the Balance End of the Year for Accunt 107 or $1,000,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Accunt 107)
(a)1b)
1 State of Washington
2 Transportation Equipment 2,792,027
3 Minor Projects (37) under $1,000,000 3,824,985
4
5 State of Idaho
6 Transportation Equipment 1,132,768
7 Minor Projects (17) under $1,000,000 2,153,017
8
9 Common WA & ID
10 Nez Perce IGrangevile Capacitor Banks 1,450,146
11 CS2 Capital Improvements 4,522,884
12 Noxon Rapids Unit 2 Runner Upgrade 1,846,097
13 Noxon Rapids Unit 3 Runner Upgrade 4,874,351
14 Clark Fork Implement PME Agreement 4,388,527
15 Transportation Equipment 1,175,440
16 Productivity Initiative 2,616,353
17 Minor Projects (68) Under $1,000,000 11,456,367
18
19 Common-WAIID/OR
20 Minor Projects (0) Under $1,000,000
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 42,232,962
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612010
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILIT PLANT (Accunt 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electic plant in service, pages 204207, column 9d), excluding retirements of non-depreciable propert.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accunting.
ine
No.
em
(a)
Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
6 Transportation Expenses-Clearing
7 Other Clearing Accounts
8 Other Accunts (Specify, details in footnote):
9
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
13 Cost of Removal
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
16 Other Debit or Cr. Items (Describe, details in
footnote):
463,364 463,364
67,313,184 67,313,184,~ ~~~
9,996,542
5,023,358
1,015,075
14,004,825
9,996,542
5,023,358
1,015,075
14,004,825
179,908
17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
10,15,16, and 18)
910,060,974 910,060,974
20 Steam Production
21 Nuclear Production
22 Hydraulic Production-Conventional
23 Hydraulic Production-Pumped Storage
24 Other Production
Section B. Balances at End of Year According to Functional Classification
246,871,127 246,871,127
98,008,475 98,008,475
25 Transmission
26 Distribution
27 Regional Transmission and Market Operation
28 General
54,250,986
158,504,412
306,761,947
45,664,027
54,250,986
158,504,412
306,761,947
45,664,027
FERC FORM NO.1 (REV. 12-05)Page 219
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) nA Resubmission 04/16/2010
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Accunt 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable propert.
3. The provisions of Accunt 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accunting.
ine
No.
Item
(a)
Section A. Balances and Changes During Year
( .! qtfl!) eleÇ\ric t'iam inc+a+e ~ervice(b) (c)eiecmc ,:iam. rieiofor Future Use
(d)
electriC t",ts.mLeased to vthers
(e)
29 TOTAL (Enter Total of lines 20 thru 28)910,060,974 910,060,974
FERC FORM NO.1 (REV. 12-05)Page 219
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
INVESTM NTS IN SUBSIDIARY COMPANIES Accunt 123.1)
1. Report below investments in Accunts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each securit owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewaL.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Accunt 418.1.
ine Description of investment Date Acquired Date Of Amount or Investment at
No.Mal~ity Beginning of Year
(a)(b)(d)
1
2 Avista Capital - Common Stock 1997 184,251,609
3 Avista Capital - Equity in Eamings -99,660,867
4 OCI Investment in Subs
5 Avista Capital - Other Changes in Net Investment -7,748,538
6 Avista Capital- Other Changes in Net Investment 645,758
7 Avista Capital - Other Changes in Net Investment
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42 Total Cost of Account 123.1 $01 TOTAL 77,487,962
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04(2) DA Resubmission 04/16/2010
INVESTMENT S IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4. For any securities, notes, or accunts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or securit acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the sellng price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equity.in Subsidiary Kevenues Tor Year Amount OT investment at üain or LOSS Trom Investment LineEarnin~s of Year End lJ)Year DiSPt~fd of No.e)(f)
1
3,683,735 187,935,344 2
827,452 -8,168,341 -107,001,757 3
4
7,748,538 5
-645,758 6
309,652 309,652 7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
'30
31
32
33
34
35
36
37
38
39
40
41
827,452 2,927,826 81,243,239 42
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2009/04(2) DA Resubmission 04/1612010 End of
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are accptable. In column (d), designate the department or departents which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accunts (operating expenses, clearing accunts, plant, etc.) affcted debited or credited. Show separately debit or crdits to stores expense
clearing, if applicable.
Line Accunt Balance Balance Department or
No.Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
1 Fuel Stock (Account 151)3,673,039 4,294,013 (1 )
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Exracted Products (Account 153)
4 Plant Materials and Operating Supplies (Accunt 154)
5 Assigned to - Construction (Estimated)10,461,384 12,289,004 (1) ....
........................ ..
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)2,106,403 2,161,593 (1)
....
......
8 Transmission Plant (Estimated)27,135 55,859 (1 )
9 Distribution Plant (Estimated)227,359 280,550 (1 ). .......
10 Regional Transmission and Market Operation Plant (1 ),(2)
(Estimated)I
11 Assigned to - Other (provide details in footnote)4,633,554 3,599,503 (1 ),(2).
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)17,455,835 18,386,509
13 Merchandise (Accunt 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Accunt 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Accunt 163)12,832
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)21,128,874 22,693,354
FERC FORM NO.1 (REV. 12-05)Page 227
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2010
Transmission Service and Generation Interconnection Study Costs
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the accunt charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the accunt credited with the reimbursement received for perfrming the study.
me
No.
YearlPeriod of Report
End of 2009/Q4
Description
(a)
1 Transmission Studies
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Costs Incurred During
Period
(b)
eim ursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
Account Charged
(c)- - - - --- -- -- - - --
Generation Studies
Horizon Wind Interconnect
Avista - Reardan Project
Avista - Garfeld Project
BP Wind Interconnect
PPM Energy Wind Interconnect
Avista - Grangeville Wind
Martinsdale Wind Interconnect
Palouse Wind Interconnect
Kellogg Biomass Interconnect
ADAGE Biomass Interconnect
Hawkstone Solar Interconnect
RES Tekoa Wind Interconnect
ADAGE Deary Biomass
186200
186200
186200
186200
186200
186200
186200
186200
186200
186200
186200
186200
186200
FERC FORM NO. 1/1-F/3-0 (NEW. 03-07)Page 231
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/1612010
o HER REGULATORY ASSETS (Accunt 182.3)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Accunt 182.3 at end of period, or amounts less than $100,000 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of WOlen 011 uunng -Wfttten ott Dunng Current QuarterlY ear
,Current the Quarterl ear the Period
QuarterlYear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
1 Regulatory Asset FAS 106 1,891,008 926,107 472,752 1,418,256
2 Guarantee Residual Value-Airplane 2,936,173 186,228 2,936,173
3 Reg Asset Post Ret Liab 172,271,747 228 31,192,90 141,084,843
4 Regulatory Asset FAS109 Utilit Plant 99,465,025 283 17,109,789 82,355,236
5 Regulatory Asset FAS109 DSIT Non Plant 3,30,888 283 919,062 2,387,826
6 Regulatory Asset FAS109 DFIT State Tax Cr 4,56,230 1,679,928 6,248,158
7 Regulatory Asset FAS109 WNP3 7,866,287 283 737,482 7,128,805
8 Regulatory Asset- Spokane River Relicense 802,034 802.034
9 Regulatory Asset- Spokane River PM&E 44,350 443,350
10 Regulatory Asset- Lake CDA Fund 10,062,735 10,062,735
11 Reg Assets- Decouplings Surcharge 479,593 407 100,664 378,929
12 Regulatory Asset AMR (252,769)252,769
13 Regulatory Asset RTO Depoits- ID 212,417 560 70,806 141,611
14 Regulatory Asset BPA Residential Exchange 249,229 249,229
15 Regulatory Asset ERM Approved for Recery 29,728,184 407,419 23,494,189 6,233,995
16 ID Wind Gen AFUDC 35,194 85,282 120,476
17 Regulatory Asset Wartila Unit 2,325,253 407 560,072 1,765,181
18 MTM St Regulatory Asset 60.228,970 244 51,897,22 8,331,750
19 Regulatory Asset FAS143 Asset Retirement Obligation 3,335,279 230,124 205,034 3,130,245
20 Reg Asset AN- CDA Lake Settement 41,733,385 407,419 4,531,187 37,202,198
21 Reg Asset WA-CDA Lake Settement 1,553.54 1,553,548
22 Regulatory Asset Workers Comp
.
242 2,921,1743,097,168 175,994
23 CS2 Lev Ret 1,442,335 62,324 1,504,659
24 Regulatory Asset ID peA Deferrl 1 10,457,471 10,57,471
25 Regulatory Asset ID PCA Deferrl 2 17,080,99 557,419 17,080,994
26 Regulatory Asset ID PCA Deferrl 3 3,513,957 7,475.831 11,049,788
27 Reg Asset-Future Payments- Lake CDA 4,000,00 4.000,000
28 DSMAsset 11,894,248 11,894,248
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 455,580,547 48,769,520_151,733,551 352,616,516
FERC FORM NO. 1/3.0 (REV. 02-04)Page 232
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
M SCELLANEOUS DEFFERED DEBITS (Account 186)
1.Report below the particulars (details) called for conceming miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~~oum.Amount End of Year
Ch~~ed
(a)(b)(c)(d (e)(f)
1
2 Colstrip Common Fac.1,110,999 1,110,999
3 Regulatorv Asset-Decoupling def 589,937 335,323 254,614
4 WA Deferred Power Costs 7,223,823 7,194,374 29,449
5 WA ERM YTD Companv Band 4,000,000 7,037,637 -3,037,637
6 WA ERM YTD Contra Accunt -4,000,000 7,037,637 3,037,637
7 Regulatory Asset ROT Deposit 395,534 158,213 237,321
8 Reaulatorv Asset-Mt lease ovmt 2,795,301 360,684 2,434,617
9 Reaulatorv Asset-Mt lease pvmt 5,413,008 676,632 4,736,376
10 Colstrip Common Fac.2,355,642 2,355,642
11 Reaulatorv Asset- COLS 738,101 153,771 584,330
12 Guaranteed Residual Value-Plane 2,916,673 2,916,673
13 Prepaid airplane Lease L T 28,743 28,743
14
15 Payroll Accral
16
17 Plant Allocation of clearina ir 2,172,024 665,241 2,837,265
18
19 Misc Error Suspense 12,457 27,611 -15,154
20
21 Renewable Enerav-Cert Fees 174,000 174,000
22 Misc susp acc-non wlo 28,327 19,088 47,415
23 Unamortized AIR sale 25,767 9,678 35,445
24
25 Intangible Pension Asset
26
27 Nez Perce Settlement 181,597 5,212 176,385
28 Misc Deferred Debit Centralia 675,990 2,44 678,434
29
30 Lona Term Note Rec acc 277,158 277,158
31 Reg Asset ID-Lake Cdal 315,120 315,120
32 ID Panhandle Forest Use Permit 224,337 1,760 226,097
33 Metro-Sunset 115KV TE
34
35 UPRR Permit Conv 350,163 350,163
36 Insurance Recv CDA Lake
37 Corp reorg stk iss. costs 118,086 118,086
38 Reclass IPA acc deoosit 2,000,000 2,000,000
39 Reclass Idaho elk Fork Relic 976,731 976,731
40 Noxon Livina Faciltv Exp 67,001 67,001
41 Drv Creek Transport 366,206 366,206
42
43 PG & E Canada to N Cal trans 493,607 373,436 867,Q3
44 Misc Work Orders -=$50,000 115,729 120,130 -4,401
45 Subsidiary Billngs 2,067,825 1,980,126 87,699
46 "Null" Proiect directlv to 186 -345,705 358,350 .12,645
47 Misc. Work in Progress
48 I Deferred RegulatoriC-omm.
Expenses (See pages 350 - 351)
49 TOTAL 32,008,980 26,105,547
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010
M SCELLANEOUS DEFFERED DEBITS (Account 186)
1.Report below the particulars (details) called for concerning miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~çcum.Amount End of Year Char~ed
(a)(b)(c)(d (e)(f)
1
2 Reaulatorv Assets Consv 1,283,765 1,054,552 229,213
3 Reaulatorv Assets Consv -87,884 151,453 63,569
4 Regulatory Assets Consv 3,003,183 930,417 2,072,766
5 Reaulatory Assets Consv 253,551 101,144 152,407
6 Reaulatorv Assets Consv 447,610 307,665 139,945
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Misc. Work in Progress
48 I Deterred Reguiatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 32,008,980 26,105,547
FERC FORM NO.1 (ED. 12-94)Page 233.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
ACCUMULATED DEFERRED INCOME TAXI S (Accunt 190)
1., Report the information called for below concerning the respondent's accunting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
ILlne Descnption ana Location ~No.of Year of Year
(a)(b) (c
1 Electric
2 15,824,253 5,391,537
3
4
5
6
7 Other
8 TOTAL Electric (Enter Total of lines 2 thru 7)15,824,253 5,391,537
9 Gas
10 2,255,652 -267,754
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15 2,255,652 -267,754
11 Other 112,975,620 86,851,764
18 TOTAL (Acct 190) (Total of lines 8,16 and 17)131,055,525 91,975,547
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 0411612010
CAPITAL STOCKS (Account 201 and 2 )4)
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 1D-K Report Form filing, a specifc reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 1D-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Account 201 - Common Stock Issued
2 No Par Value 200,000,000
3 Restricted shares
4 TOTAL COM 200,000,000
5
6
7 Account 204 - Preferred Stock Issued 10,000,000
8
9
10 Cumulative
11
12
13 TOTAL PRE 10,000,000
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/16/2010
CAPITAL STOCKS (Account 201 and 2 4) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line(Total amount outstanding without reduction AS REACOUIRED STOCK (Accunt 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Sh.ares Amount Shares \Ast Sh~res Amount(e)(f)(g)(h)(i)u)
1
54,836,781 759,057,747 2-1,307,215 3
54,836,781 759,057,747 1,307,215 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 0411612010
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Report below the balance at the end of the year and the information specifed below for the respective other paid-in capital accunts. Provide a
subheading for each accunt and show a total for the account, as well as total of all accounts for reconcilation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accunting entries effcting such
change.
(a) Donations Received from Stockholders (Accunt 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Accunt 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account accrding to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
~(e ii¡r Ari)unt
o.
1 Equity transactions of subsidiaries 17,498,634
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 TOTAL 17,498,634
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) riA Resubmission 04/16/2010
CAPITAL STOCK EXPENSE (Account 214).
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line Glass and Series õfStoCk tsaiance at End of Year
No.(a)(b)
1 Common Stock - Public issue
2 CAP STOCK EXP - COMMON PUBLIC ISSUE 13,301,168
3 TAX BENEFIT - OPTIONS EXERCISED -5,683,807
4 STOCK COMP INCENTIVE ACCRUAL -10,272,805
5 STOCK COMP - SUBS -849,764
6 SHARE WITHHOLDING 1,414,247
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL -2,090,961
FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
LONG-TERM DEBT (Accunt 221, 222, 223 and 224)
1. Report by balance sheet accunt the particulars (details) concerning long-term debt included in Accunts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accunts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certifcates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accunts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 FMBS - SERIES C - 8.02% DUE 10/26/2010 25,000,000 868,814
2 FMBS - SERIES C - 6.37% DUE 06/18/2028 25,000,000 346,953
3 FMBS - SERIES A - 6.67% DUE 7/12/2010 5,000,000 725,545
4 FMBS - SERIES A -7.37% DUE 5/10/2012 7,000,000 1,276,997
5 FMBS - SERIES A - 7.39% DUE 5/11/2018 7,000,000 1,282,247
6 FMBS - SERIES A - 7.45% DUE 6/11/2018 15,500,000 2,311,037
7 FMBS - SERIES A - 7.53% DUE 05/0512023 5,500,000 1,005,723
8 FMBS - SERIES A - 7.54% DUE 5/05/2023 1,000,000 183,178
9 FMBS - SERIES A - 7.18% DUE 8111/2023 7,000,000 54,364
10 FMBS - SERIES B - 6.9% DUE 07101/2010 5,000,000 37,944
11 COLSTRIP 1999B PCBS DUE 2034 17,000,000 4,051,718
12 COLSTRIP 1999A PCBS DUE 2032 66,700,000 3,330,522
13 FMBS - 6.125% DUE 09-01-2013 45,000,000 1,870,964
14 KETTLE FALLS P C REV BONDS DUE 14 4,100,000 282,248
15 5.45% SERIES DUE 12-01-2019 90,000,000 1,432,081
16 FMBS - 6.25% DUE 12-01-35 150,000,000 -2,137,016
17 FMBS - 5.70% DUE 07-01-2037 150,000,000 8,663,162
18 5.95% SERIES DUE 06-01-2018 250,000,000 19,476,419
19 7.25% FMB'S DUE 2013 30,000,000 420,306
20 5.125% SERIES DUE 04-01-2022 250,000,000 -7,701,222
21 ADVANCE ASSOCIATED-AVISTA CAPITAL II (ToPRS)51,547,000 -1,203,914
22 INTEREST RATE SWAPS
23
24
25
26
27
28
29
30
31
32
33 TOTAL 1,207,347,000 36,578,070
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/16/2010
LONG-TERM DEBT (Account 221,222,22 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Accunt 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD OLltstanciing LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
respy~dent)
(i)
10-26-1999 10-26-2010 25,000,000 2,005,000 1
06-19-1998 06-19-2028 25,000,000 1,592,500 2
07-12-1993 07-12-2010 5,000,000 333,500 3
05-10-1993 05-10-2012 7,000,000 515,900 4
05-11-1993 05-11-2018 7,OOO,OOC 517,300 5
06-09-1993 06-11-2018 15,500,OOC 1,154,750 6
05-06-1993 05-05-2023 5,500,000 414,150 7
05-07-1993 05-05-2023 1,000,000 75,400 8
08-12-1993 08-11-2023 7,000,000 502,600 9
06-09-1995 07-01-2010 5,000,000 345,000 10
03-01-1994 03-01-2034 61,675 11
03-01-1994 06-01-2032 12
09-08-2003 09-01-2013 45,000,000 2,756,250 13
12-01-1993 12-01-2023 4,100,000 246,000 14
11-18-2004 12-01-2019 90,000,000 4,905,000 15
11-17-2005 12-01-2035 150,000,000 9,375,000 16
12-15-2006 07-01-2037 150,000,000 8,550,000 17
04-02-2008 06-01-2018 250,000,000 14,875,000 18
12-16-2008 12-16-2013 30,000,000 2,175,000 19
09-22-2009 04-01-2022 250,000,000 12,812,500 20
06-03-1997 06-01-2037 51,547,000 952,275 21
-1,843,577 22
23
24
25
26
27
28
29
30
31
32
1,121,803,423 64,164,800 33
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 0411612010
RECONCILIATION OF REP¡RTED NET INCOME WITH TAXBLI INCOME FOR FEDERAL INCOME TAXES
1. Report the reconcilation of reported net income for the year with taxable income used in computing Federal income tax accals and show
computation of such tax accruals. Include in the reconcilation, as far as practicable, the same detail as fumished on Schedule M-1 of the tax return for
the year. Submit a reconcilation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utilty is a member of a group which files a consolidated Federal tax return, 'reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substiute Page in the context of a footnote.
Line Particulars (Details)Amount
No.(a)(b)
1 Net Income for the Year (Page 117)87,071,250
2
3
4 Taxable Income Not Reported on Books
5 1,911,534
6
7
8
9 Deductions Recorded on Books Not Deducted for Return
10 102,619,036
11 Federal Income Tax 28,968,355
12 Deferred Income Tax 13,224,479
13 Investment Tax Credit 2,017,491
14 Income Recorded on Books Not Included in Return
15 60,745,269
16 Equity in Sub Earnings (Income)/Loss 827,452
17 Corporated Overhead Unallocated Subs 769,980
18
19 Deductions on Return Not Charged Against Book Income
20 229,909,385
21
22
23
24
25
26
27 Federal Tax Net Income
28 Show Computation of Tax:
29 State Tax ~2% Less Idaho ITC 2,111,405
30 Federal Tax Net Income, less State Tax 68,701,962
31
32 Federal Tax ~ 35%24,045,687
33 Prior years tax return, revenue agent reports & misc true ups 6,601,983
34 Kettle Falls & Cabinet Gorge tax credit 1,679,315
35 otal Federal Tax Expense 28,968,355
36
37
38
39
40 .
41
42
43
44
FERC FORM NO.1 (ED. 12-96)Page 261
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 0411612010
TAXES ACCRUED, PREPAID AND CHA GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accunts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have been charged to the accunts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accunts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accunts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accunts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
¡L.ine Kind ofTax BALANCE AT BEGINNING OF YEAR ~xesd '~~fås Adjust-argeNo.(See instruction 5)1. axes Accrueø prepald Taxes ~ring ~ring ments
(Account 236)(Include in Account 165)ear ear
(a)(b)(c)(d)(e)(f)
1 FEDERAL:
2 Income Tax Prior 25,778,732
3 Income Tax 2006 -18,141,202 992,601 6,639,496
4 Income Tax 2007 -2,300,314 -151,670 -1,997,498
5 Income Tax 2008 -11,031,901 13,123,056 -8,677,741
6 Income Tax (Current)12,352,670 31,248,211
7 Retained Earnings
8 Prior Retained Earnings -5,013,521 -2,415
9 Prior Retained Earnings -2,127,838
10 Prior Retained Earnings -1,435,621
11 Current Retained Earnings -1,210,371
12 Total Federal -14,271,665 25,103,871 27,212,468
13
14 STATE OF WASHINGTON:
15 Propert Tax (2008)7,771,174 -1,318,164 6,453,010
16 Propert Tax (2009)7,086,952 -346
17 Excise Tax (2005)91,452
18 Excise Tax (2006)-464
19 Excise Tax (2007)400,000
20 Excise Tax (2008)2,485,298 -11,891 2,473,407
21 Excise Tax (2009)25,168,760 22,903,217
22 Natural Gas Use Tax 33,215 47,598 65,704
23 Municipal Occupation Tax 2,614,786 23,012,125 23,191,538
24 Sales & Use Tax (2006)-7,943 -295 -65
25 Sales & Use Tax (2007)13,643 13,643
26 Sales & Use Tax (2008)50,265 50,265
27 Sales & Use Tax (2009)868,665 784,475
28 Motor Vehicle Tax (2009)15,574 15,574
29 Total Washington 13,451,426 54,869,324 55,950,768 -346
30
31 STATE OF IDAHO:
32 Income Tax (2006)487,826 141,437
33 Income Tax (2007)-104,516
34 Income Tax (2008)-443,776 342,216
35 Income Tax (2009)469,890 760,000
36 Propert Tax (2008)2,512,135 -157,401 2,354,513 -221
37 Propert Tax (2009)3,937,283 1,956,011 -22,381
38 Motor Vehicle Tax (2009)9,347 9,347
39 Sales & Use Tax (2005)436
40 Sales & Use Tax (2007)-13 13
41 TOTAL 6,105,577 104,962,934 108,845,885 1
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) r=A Resubmission 04116/2010
TAXES ACCF UED, PREPAID AND CHARGED DU ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertining to other utiit departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utilty plant or other balance sheet accounts.
9. For any tax apportioned to more than one utilty department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items . AOJustmems to Ket.Other No.Acco~nt 236)(Incl. in Accunt 165)(Accunt 408.1, 409.1)(Accunt 409.3)Earnings (Account 439)
g)(h)(i)ü)(k)(I)
1
25,778,732 2
-23,788,097 -100,641 1,093,242 3
-454,486 98,001 -249,670 4
10,768,896 .135,923 12,987,133 5
-18,895,541 13,438,692 -1,086,022 6
7
-5,015,936 -2,415 8
-2,127,838 9
-1,435,621 10
-1,210,371 -1,210,371 11
-16,380,262 13,571,975 11,531,897 12
13
14
-1,059,373 -258,791 15
7,086,606 5,405,952 1,681,000 16
91,452 17
-464 18
400,000 19
-16,589 4,698 20
2,265,543 17,235,991 7,932,769 21
15,109 47,598 22
2,435,373 15,480,504 7,531,621 23
-8,173 -295 24
25
26
84,190 868,665 27
15,574 28
12,369,636 37,046,485 17,822,839 29
30
31
346,389 32
-104,516 33
-101,560 313,024 29,192 34
-290,110 380,356 89,534 35
-57,910 -99,491 36
1,958,891 3,206,068 731,215 37
9,347 38
436 39
13 40
2,222,627 66,499,694 38,463,240 41
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) riA Resubmission 04/1612010
fA ES ACCRUED, PREPAID AND CHA GED DURING YEAR
1. Give particulars (details) of the combined prepaid and acced tax accunts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have been charged to the accunts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accunts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affcted by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to currnt year, and (c) taes paid and charged direct to operations or accounts other
than accued and prepaid tax accunts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
..me Kind ofTax BALANCE AT BEGINNING OF YEAR C1~xesd '~~lås Adjust-argeNo.(See instruction 5)Taxes Accrue9 ~repata i axes ~ring ~ring ments
(Accunt 236)(Include in Account 165)ear ear
(a)(b)(c)(d)(e)(1)
1 Sales & Use Tax (2008)23,236 18,888
2 Sales & Use Tax (2009)129,709 125,559
3 Irrigation Credits (2009)444
4 KW Tax (2008)21,255 -5,595 15,660
5 KW Tax (2009)338,888 322,703
6 Franchise Tax (2008)1,673,763 1,673,763
7 Franchise Tax (2009)4,511,633 2,808,008
8 Total Idaho 4,170,346 9,576,427 10,185,889 -22,602
9
10 STATE OF MONTANA:
11 Income Tax (2006)520,245
12 Income Tax (2007)-59,435 -59,435
13 Income Tax (2008)-347,781 167,207
14 Income Tax (2009)315,028 525,000
15 Propert Tax (2008)3,336,316 -8,185 3,328,131
16 Propert Tax (2009)6,173,166 3,088,756
17 Colstrip Generation Tax 3,222 3,222
18 KW Tax (2008)267,227 267,227
19 KW Tax (2009)1,008,877 788,579
20 Motor Vehicle Tax (2009)4,068 4,068
21 Consumer Council Tax 24,450 -20,548 3,899
22 Public Commission Tax 6 5,907 5,105
23 Total Montana 3,741,028 7,648,742 7,954,552
24
25 STATE OF OREGON:
26 Income Tax (2006)266,087
27 Income Tax (2007)-5
28 Income Tax (2008)-549,586 324,299 -334,870
29 Income Tax (2009)161,688 530,000
30 Property Tax (2008)-1,010,000 1,004,692 -5,308
31 Property Tax (2009)1,764,096 3,081,486
32 Motor Vehicle Tax (2009)486 486
33 BETC Credit (2006 & Prior)-498,457 77,652
34 BETC Credit (2007)209,659 33,694
35 BETC Credit (2008)-46,847 6,464
36 BETC Credit (2009)-91,881
37 Glendale Regulatory Cr. 2008 -351,469 140,580
38 Glendate Regulatory Cr. 2009 70,289
39 Franchise Tax (2006)755
40 Franchise Tax (2008)996,390 966,063
41 TOTAL 6,105,577 104,962,934 108,845,885 1
FERC FORM NO.1 (ED. 12-96)Page 262.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) r=A Resubmission 04/16/2010
TAXES ACCI UED, PREPAID AND CHARGED DU ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accunts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accunts 408.1 and 409.1
pertaining to electric operations. Report in column (i) the amounts charged to Accunts 408.1 and 109.1 pertaining to other utilty departments and
amounts charged to Accunts 408.2 and 409.2. Also shown in column (i) the taxes charged to utilty plant or other balance sheet accunts.
9. For any tax apportioned to more than one utilty department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items . l\oJustments to Ke!.Other No.ACC~m236)(Incl. in Account 165)(Accunt 408.1, 409.1)(Account 409.3)Earnings (Account 439)
(h)(i)0)(k)(I)
4,348 1
4,150 129,709 2
444 444 3
-5,595 4
16,185 338,888 5
6
1,703,625 2,955,248 1,556,385 7
3,538,282 7,130,523 2,445,904 8
9
10
520,245 11
12
-180,574 167,207 13
-209,972 315,028 14
-8,185 15
3,084,410 6,173,166 16
3,222 17
18
220,298 1,008,877 19
4,068 20
3 -20,58 21
808 5,907 22
3,435,218 7,644,674 4,068 23
24
25
266,087 26
-5 27
109,583 -1 324,300 28
-368,312 87,446 74,242 29
79,000 925,692 30
-1,317,390 939,758 824,338 31
486 32
-420,805 77,652 33
243,353 33,694 34
-40,383 6,464 35
-91,881 -91,881 36
-210,889 140,580 37
70,289 70,289 38
755 39
30,327 40
2,222,627 66,499,694 38,463,240 41
FERC FORM NO.1 (ED. 12-96)Page 263.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) r=A Resubmission 0411612010
TAXES ACCRUED, PREPAID AND CHA GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accunts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have been charged to the accunts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accunts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affcted by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accunts other
than accued and prepaid tax accunts.
4. List the aggregate of each kind of ta in such manner that the total ta for each State and subdivision can readily be ascertained.
Line Kind ofTax BALANCE AT BEGINNING OF YEAR ~~es T~~taS Adjust-C argedNo.(See instruction 5)T axes AccrueØ ~repald Taxes ~ring ~ring ments
(Account 236)(Include in Account 165)ear ear
(a)(b)(c)(d)(e)(f)
1 Franchise Tax (2009)4,284,846 3,287,865
2 Total Oregon -983,473 7,776,905 7,525,722
3
4 STATE OF CALIFORNIA:
5 Income Tax (2005)-1,869
6 Income Tax (2006)-314
7 Income Tax (2007)-3,200 800 2,400
8 Income Tax (2008)2,400 -2,400
9 Income Tax (2009)2,400
10 Total California -5,383 3,200 2,400
11
12 MISCELLANEOUS STATES:
13 Income Tax (2007)
14 Income Tax (2008)-1 1
15 Total Misc States -1 1
16
17 COUNTY & MUNICIPAL
18 WA Renewable Energy -8,863 -8,863
19 Misc.3,299 -6,673 22,949 22,949
20 Total County 3,299 -15,536 14,086 22,949
21
22
23
24
25
26
27
28
29
30
31
32
33
.34
35
36
37
38
39
40
41 TOTAL 6,105,577 104,962,934 108,845,885 1
FERC FORM NO.1 (ED. 12-96)Page 262.2
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
TAXES ACCF UED, PREPAID AND CHARGED DU ING YEAR (Continued)
5. If any ta (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (t) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (i) only the amounts charged to Accunts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utiit departments and
amounts charged to Accunts 408.2 and 409.2. Also shown in column (i) the taxes charged to utilty plant or other balance sheet accunts.
9. For any tax apportioned to more than one utilty department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line(Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Rel.Other No.ACCO~m236)(Inc!. in Account 165)(Account 408.1, 409.1)(Account 409.3)Earnings (Accunt 439)
(h)(i)u)(k)(i)
996,981 -166 4,285,012 1
-732,290 1,106,037 6,670,868 2
3
4
-1,869 5
-314 6
800 7
2,400 8
-2,400 9
-4,583 3,200 10
11
12
13
14
15
16
17
-8,863 18
-3,374 -6,673 19
-3,374 -15,536 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
2,222,627 66,499,694 38,463,240 41
FERC FORM NO.1 (ED. 12-96)Page 263.2
Name of Respondent ThiS~rIS:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) A Resubmission 04/16/2010
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Accunt 255)
Report below information applicable to Accunt 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any correction adjustments to the accunt balance shown in column (g).Include in column (i)
the average period over which the tax credits are amortized.
ine Accunt
No.Subdi~~sions of Year Deferred for Year Current Year's Income Adjustments
(b) Account NO. Amount ACCOunt NO. Amount (g)(c) (d) (e) (f)
1 Electric Utiity
23%
34%
47%
510%
6 236000 5,308,088
7
8 TOTAL 5,308,088
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10 Gas Propertry (100%373,728 411400 49,30e
11
12 TOTAL PROPERTY 373,728 49,30e
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 .
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/1612010
ACCUMULATED D FERRED INVESTMENT TAX CRED TS (Account 255) (continued)
~ADJUSTMENT EXPLANATION Lineof Year of AI ocation No.to Incomeh i I-
1
2
3
4
5
5,308,088 6
7
5,308,088 8
9
324,420 10
11
324,420 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
o HER DEFFERED CREDITS (Accunt 253)
1. Report below the particulars (details) called for concerning '?ther deferred crdits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Accunt 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(a)(b)
Account
(f)(c)(d)(e)
1 Defer Gas Exchange(253028)2,119,525 2,119,525
2 Pacificorp Capacitor (253080)4,686 456 4,686
3 Centralia Environmental (253110)963,886 2,437 966,323
4 Rathdrum Refund (253120)374,864 550 33,822 341,042
5 NE Tank Spil (253130)98,607 550 11,502 87,105
6 Bils Pole Rentals (253140)211,620 3,583 215,203
7 CR-CS2 GE L TSA (253150)4,739,221 232 2,326,663 2,412,558
8 IR Swaps (254170)568,713 176 568,713
9 Regulatory Accuals(253650)4,000,000 232 4,000,000
10 SalelLeaseback on Bldg (253850)784,368 931 261,456 522,912
11 Clark Fork Relicensing (253890)-1,223,720 1,223,720
12 Defer Comp Retired Execs (253900)180,448 431,232 61,274 119,174
13 Defer Comp Active Execs (253910)8,807,721 628,908 9,436,629
14 Executive Incent Plan (253920)140,000 140,000
15 Un biled Revenue (253990)5,335,468 634,860 5,970,328
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 24,985,882 7,268,116 4,613,033 22,330,799
FERC FORM NO.1 (ED. 12-94)Page 269
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612010
ACCUMULATE DEFFERED INCOME TAXES - OT ER PROPERTY (Accunt 82)
1. Report the information called for below conceming the respondent's accunting for deferred income taxes rating to propert not
subject to acclerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Accunt 411.1
(d)(a)(b)
1 Account 282
2 Electric
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4)
6
7
8
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classifcation of TOTAL
11 Federal Income Tax
12 State Income Tax
13 Local Income Tax
252,105,800
70,244,199
12,542,042
334,892,041
15,828,047
7,534,446
4,128,701
27,491,194
936,721
936,721
334,892,041 27,491,194 936,721
323,825,718
11,066,323
27,491,194 936,721
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2010
E TAXES - OTHER PROPERTY (Account 282) (Continued)
YearlPeriod of Report
End of 2009/04
ACCUMULATED DEFERRED INCO
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.2 to Account 411.2
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
Debits
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612010
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Accunt 283)
1. Report the information called for below concerning the respondent's accunting for deferred income taxes relating to amounts
recorded in Accunt 283.
2. For other (Specify),include deferrals relating to other income and deductions.
YearlPeriod of Report
End of 2009/04
Name of Respondent
Avista Corporation
Line
No.
Accunt
(a)
Balance at
Beginning of Year
(b)
1 Account 283
2 Electric
3 Electric
4
5
6
7
8
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
11 Gas
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 Other
19 TOTAL (Acc 283) (Enter Total of lines 9, 17 and 18)
20 Classifcation of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
48,019,117
31,845
402,332
-3,135,591 301,512
48,453,294 -3,135,591 301,512
-6,439,429 -6,495,357 -143,255
-6,439,429 -6,495,357 -143,255
246,729,622 -864,923
288,743,487 -10,495,871 158,257
279,078,915 -10,495,871 158,257
9,664,572
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612010
ACCUMULATED EFERRED INCOME TAXES - OTHE (Accunt 283) (Continue)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignifcant items listed under Other.
4. Use footnotes as required.
ADJUSTMENTS
Line
No.
541,021 15,771
182 1,291,333
45,107,264
-1,259,488
402,332
4
541,021 15,771 1,291,333 44,250,108
172,486 232,857 -12,851,902
190 21,363 -21,363
283 69,458 -69,458
172,486 232,857 90,821 -12,942,723
-301,246 3,372,019 182,190 47,988,448 283 69,458 194,272,444
412,261 3,620,647 49,370,602 69,458 225,579,829
412,261 3,620,647 43,939,836 69,458 221,346,023
5,430,766 4,233,806
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
o HER REGULATORY LIABILITIES (Accunt 254)
1. Report below the particulars (details) called for conce.ming other regulatory liabilties, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Accunt 254 at end of period, or amounts less than $100,000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilties being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End
Line Description and Purpose of of Current of Current
No.Other Regulatory Liabilities OuarterlYear ~ccunt Amount Credits QuarterlYearCredited
(a)(b)(c)(d)(e)(f)
1 Idaho Investment Tax Credit (254005)8,354,865 3,248,858 11,603,723
2 Oreon BETC Credit (254010)128,992 190 128,992
3 Noxon, ITC (254025)1,41,110 1,441,110
4 Defer Gas Exchange (254028)1,597,806 142,495 1.597,806
5 FAS 109 Invest Tax Credit (254180)201,240 190 26,556 174.684
6 Nez Perc (254220)770,396 557 22,008 748,388
7 Oreon Senate Bil (254250)1,450.000 407 662,125 1 ,001 ,m 1,789,652
8 Reg liabilty CCXCR ID (254300)754,484 407 413,972 340,512
9 Accrue Lake CDA IPA int (254325)64,410 64,410
10 BPA Res Exch Regulatory Liab (254345)2,900.393 2,900,393
11 Unrealized Currency Exchange (254399)35.548 35,548
12 Reg Liabilty Other (254700)
13 Mark to Market ST (254740)
14 Mark to Market FAS133 (254750)42,171.739 439,754 42,611,493
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 55,29,522 2,851,459 9,131,850 61,709,913
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/16/2010
ELECTRIC OPERATING REVENUES ( ccunt 400)
1. The following instructions generally apply to the annual version of these pages. Do not report quarterl data in columns (c), (e), (f), and (g). Unbiled revenues and MW
related to unbiled revenues nee not be reported separately as required in the annual version of these pages.
2. Report below operatng revenues for each prescribed accunt, and manufactured gas revenues in total.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accunts; except that where separate meter readings are added
for biling purpses, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived frm previously reported figures, explain any inconsistencies in a footnote.
5. Disclose amounts of $250,000 or greater in a footnote for accunts 451,456, and 457.2.
Line Title of Accunt Operating Revenues Year Operating Revenues
No.to Date Quarterll Annual Previous year (no Quartrly)
(a)(b)(c)
1 Sales of Electricity
2 (440) Residential Sales 315,648,544 279,640,876
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)273,953,602 247,713,799
5 Large (or Ind.) (See Instr. 4)107,741,463 101,785,110
6 (444) Public Street and Highway Lighting 6,607,434 5,961,756
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales 1,075,772 980,339
10 TOTAL Sales to Ultimate Consumers 705,026,815 636,081,880
11 (447) Sales for Resale 198,516,063 224,672,881
12 TOTAL Sales of Electricit 903,542,878 860,754,761
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds 903,542,878 860,754,761
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues 651,836 570,818
18 (453) Sales of Water and Water Power 381,238 306,684
19 (454) Rent from Electric Propert 2,742,428 2,774,767
20 (455) Interdepartental Rents
21 (456) Other Electric Revenues 34,534,405 47,550,273
22 (456.1) Revenues from Transmission of Electricity of Others 9,176,474 9,428,833
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Oter Operating Revenues 47,486,381 60,631,375
27 TOTAL Electric Operating Revenues 951,029,259 921,386,136
FERC FORM NO.1/3-Q (REV. 12-oS)Page 300
Name of Respondent
Avista Corporation
This ~ort Is:(1) ~An Original
(2) A Resubmission
E ECTRIC OPERATING REVENUES (
Date of Report
(Mo, Da, Yr)
04116/2010
ccunt400)
YearlPeriod of Report
End of 2009/Q4
6. Commercial and industrial Sales, Accunt 442, may be classified accrding to the basis of classification (Small or Commercial, and Large or Industrial) regularl used by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Accunt 442 of the Uniform System of Accunts. Explain basis of classification
in a footnote.)
7. See pages 108.109, Important Changes During Period, for importnt new territory added and importnt rate increase or decreases.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbiled revenue by accunts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Ouarterly) Previous Year (no Ouarterly) No.(f) (g)
3,176,670 3,187,832 39,276 39,075 4
1,947,553 2,058,527 1,394 1,388 5
26,021 25,757 444 434 6
7
8
13,371 13,507 80 74 9
8,954,984 9,029,319 355,078 352,352 10
4,737,063 3,566,073 11
13,692,047 12,595,392 355,078 352,352 12
13
13,692,047 12,595,392 355,078 352,352 14
Line 12, column (b) includes $
Line 12, column (d) includes
6,581,138 of un biled revenues.
52,131 MWH relating to unbiled revenues
FERC FORM NO. 1/3-0 (REV. 12-05)Page 301
Name of Respondent This in0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
SALES OF ELECTRICITY BY RATE S(HEDULES
1. Report below for each rate schedule in effct during the year the MW of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accunt in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicable revenue accunt subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accunt classifcation (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of biling periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
ine NumOer ano I me or t(ate scneauie Mwn~oia Revenue Average Numoer 1\ wn ofSes ~is~krNo.(a)(b)(c)of c~~\omers Per ?~stomer
(f)
1 RESIDENTIAL SALES (440)
2 1 Residential Service 3,634,114 290,440,480 299,715 12,125 0.0799
3 2 Residential Service
4 3 Residential Service
5 12 Res. & Farm Gen. Service 66,429 7,593,985 12,365 5,372 0.1143
E 15 MOPS II Residential
7 22 Res. & Farm Lg. Gen. Service 49,691 3,926,588 103 482,437 0.0790
8 30 Pumping-Special
9 32 Res. & Farm Pumping Service 14,132 1,183,579 1,701 8,308 0.0838
10 48 Res. & Farm Area Lighting 4,690 1,073,658 0.2289
11 49 Area Lighting-High-Press.281 72,087 0.2565
12 56 Centralia Refund
13 95 Wind Power 174,792 .
14 72 Residential Service
15 73 Residential Service
16 74 Residential Service
17 76 Residential Service
18 77 Residential Service
19 58A Tax Adjustment -46,91E
20 58 Tax Adjustment 8,292,835
21 SubTotal 3,769,337 312,711,086 313,884 12,009 0.0830
22 Residential-Unbiled 22,032 2,937,458 0.1333
23 Total Residential Sales 3,791,368 315,648,544 313,884 12,079 0.0833
24
25 COMMERCIAL SALES (442)
2E 2 General Service
27 3 General Service
28 11 General Service 664,262 68,279,239 33,746 19,684 0.1028
29 12 Res. & Farm Gen. Service
30 16 MOPS II Commercial
31 19 Contract-General Service
32 21 Large General Service 2,029,033 164,397,447 4,496 451,297 0.0810
33 25 Extra Lg. Gen. Service 360,289 20,172,762 13 27,714,538 0.0560
34 28 Contract-Exra Large Serv
35 31 Pumping Service 93,901 6,933,108 1,021 91,970 0.0738
36 47 Area Lighting-Sod. Vap 6,648 1,342,337 0.2019
37 49 Area Lighting-High-Press.2,383 491,797 0.2064
38 56 Centralia Refune
39 95 Wind Power 59,072
40 74 Large General Service
41 TOTAL Biled 13,639,91E 896,961,74C 355,07f 38,41'0.065f
42 Total Unbiled Rey.(See Instr. 6)52,131 6,581,13S C (0.126.
43 TOTAL 13,692,041 903,542,878 355,07f 38,561 0.066C
FERC FORM NO.1 (ED. 12-95)Page 304
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effct during the year the MW of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accunt in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue accunt subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of biling periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
Line Numoer ana Iitie or Kate scneouie Mvvn ;:010 Kevenue l\verage Numoer ~vvn_oT ;;aies rw~~~rcrNo.(a)(b)(c)
of c~~\omers Per C(~stomer
(f)
1 75 Large General Service
2 76 Large General Service
3 77 General Service
4 58A Tax Adjustment -46,808
5 58 Tax Adjustment 9,499,450
6 SubTotal 3,156,516 271,128,404 39,276 80,368 0.0859
7 Commercial-Unbiled 20,154 2,825,198 0.1402
8 Total Commercial 3,176,670 273,953,602 39,276 80,881 0.0862
9
10 INDUSTRIAL SALES (442)
11 2 General Service
12 3 General Service
13 8 Lg Gen Time of Use
14 11 General Service 6,552 688,918 232 28,241 0.1051
15 12 Res. & Farm Gen. Service
16 21 Large General Service 166,637 12,928,178 192 867,901 0.0776
17 25 Extra Lg. Gen. Service 1,677,279 86,076,255 20 83,863,950 0.0513
18 28 Contract - Extra Large Service 68 219,109 3.2222
19 29 Contract Lg. Gen. Service
20 30 Pumping Service - Special 23,689 1,544,497 34 696,735 0.0652
21 31 Pumping Service 57,865 4,455,491 759 76,238 0.0770
22 32 Pumping Svc Res & Firm 5,235 396,960 157 33,344 0.0758
23 47 Area Lighting-Sod. Vap.232 39,472 0.1701
24 49 Area Lighting - High-Press 51 9,435 0.1850
25 95 Wind Power 1,728
26 72 General Service
27 73 General Service
28 74 Large General Service
29 75 Large General Service
30 76 Pumping Service
31 77 General Service
32 58A Tax Adjustment -1,124
33 58 Tax Adjustment 564,062
34 SubTotal 1,937,608 106,922,981 1,394 1,389,963 0.0552
35 Industrial-Unbiled 9,945 818,482 "0.0823
36 Total Industrial 1,947,553 107,741,463 1,394 1,397,097 0.0553
37
38 STREET AND HWY LIGHTING (444)
39 6 Mercury Vapor St. Ltg.
40 7 HP Sodium Vap. St. Ltg
41 TOTAL Biled 13,639,916 896,961,740 355,07f 38,414 0.065€
42 Total Unbiled Rev.(See Instr. 6)52,131 6,581,138 (C 0.126~
43 TOTAL 13,692,041 903,542,878 355,07f 38,561 0.066C
FERC FORM NO.1 (ED. 12-95)Page 304.1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effct during the year the MW of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accunt in the sequence followed. in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of billing periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
I Line Numoer ana I me OT Kate scneauie MWn::Ola Revenue Average Number I\WnOT ::aies ~~~rderNo.(a)(b)(c)ofC~~omers Per yà)stomer
(f)
1 11 General Service
2 41 Co-Owned St. Lt. Service 219 39,152 16 13,688 0.1788
3 42 Co-Owned St. Lt. Service 20,309 5,938,023 363 55,948 0.2924
4 High.Press. Sod. Vap.
5 43 Cust-Owned St. Lt. Energy 9 847 1 9,000 0.0941
6 and Maint. Service
7 44 Cust-Owned St. Lt. Energy 843 116,215 28 30,107 0.1379
8 and Maint. Svce - High-Pres
9 Sodium Vapor
10 45 Cust. Owned St. Lt. Energy Svc 1,329 89,708 6 221,500 0.0675
11 46 Cust. Owned St. Lt. Energy Svc 3,312 297,106 30 110,400 0.0897
12 58A Tax Adjustment -664
13 58 Tax Adjustment 127,047
14 SubTotal 26,021 6,607,434 444 58,606 0.2539
15 Street & Hwy Lighting-Unbiled
16 Total Street & Hwy Lighting 26,021 6,607,434 444 58,606 0.2539
17
18 OTHER SALES TO PUBLIC
19 (445)
20 None
21
22 INTERDEPARTMENTAL SALES 13,371 1,075,772 8C 167,138 0.0805
23 58 Tax Adjustment
24 Total Interdepartmental 13,371 1,075,772 80 167,138 0.0805
25
26 SALES FOR RESALE (447)
27 61 Sales to Other Utilties (NDA)4,737,063 198,516,063 0.0419
28
29
30 Total Sales for Resale 4,737,063 198,516,063 0.0419
31
32
33
34
35
36
37
38
39
40
41 TOTAL Biled 13,639,91E 896,961,740 355,071 38,414 0.065E
42 Total Unbiled Rev.(See Instr. 6)52,131 6,581,138 (C 0.126..
43 TOTAL 13,692,047 903,542,878 355,071 38,561 0.066C
FERC FORM NO.1 (ED. 12-95)Page 304.2
This Page Intentionally Left Blank
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/1612010
SALES FOR RESALE (Accunt 4 7)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricit ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera~e Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly iIing Avera~e Aver~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 BC Transmission Corp.SF Tariff 12
2 Barclays Bank PLC SF WSPP-C
3 Barclays Bank PLC SF.\/.ISDA
4 Black Hils Power, Inc.SF WSPP-C
5 BP Corporation North America, Inc.I!iì: ..... ./;ISDA
6 BP Energy Company SF WSPP-C
7 Bonnevile Power Administration LF Tariff 8
8 Bonnevile Power Administration LF BPAOATT
9 Bonnevile Power Administration SF WSPP-C
10 Bonnevile Power Administration SF Tariff 12
11 Cargil Power Markets, LLC SF WSPP-C
12 Cargil Power Markets, LLC SF Tariff 9
13 Chelan County PUD NO.1 SF WSPP-C
14 Citigroup Energy, Inc.SF WSPP-C
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) riA Resubmission 04/16/2010
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order.. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQlNon-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)Ü)(k)
20 434 4304 1
297,334 13,046,048 13,046,048 2
-189,600 -189,600 3
400 15,600 15,600 4
1,113,659 1,113,659 5
434,981 23,779,454 23,779,454 6
33,894 1,195,985 1,195,985 7
1,184 36,734 36,734 8
81,853 3,116,112 3,116,112 9
25 671 671 10
55,369 1,763,316 1,763,316 11
230 23C 12
3,200 112,550 112,550 13
6,600 247,350 247,350 14
0 0 0 0 0
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
SALES FOR RESALE (Accunt 4 7)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electncity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability' of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilateraiiy get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Aver~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Clatskanie Peoples PUD SF WSPP-C
2 Conoco Phillps SF WSPP-C
3 Conoco Philips SF Tariff 9
4 Constellation Energy Commodities Group SF WSPP-C
5 Credit Suisse Energy LLC SF WSPP-C
6 Douglas County PUD NO.1 SF WSPP-C
7 Douglas County PUD NO.1 SF .290
8 Eagle Energy Partners, LLP SF WSPP-C
9 Endure Energy, LLC SF WSPP-C
10 Eugene Water & Electric Board SF WSPP-C
11 Fortis Energy Marketing & Trading GP SF WSPP-C
12 Grant County PUD NO.2 SF WSPP-C
13 Grant County PUD NO.2 SF Tariff 12
14 Grant County PUD NO.2 SF 290
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.1
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this coe for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (6Q-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
2,399 54,448 54,448 1
26,208 915,195 915,195 2
122,640 122,640 3
125,066 7,687,222 7,687,222 4
47,000 764,200 764,200 5
1,458 62,252 62,252 6
5,00 5,00 7
9,600 178,100 178,100 8
6,684 249,609 249,609 9
13,036 394,772 394,772 10
50,575 1,771,800 1,771,800 11
15,715 508,230 508,230 12
16 535 535 13
600 600 14
0 0 0 0 0
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
FERC FORM NO.1 (ED. 12-90)Page 311.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricit ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly iIing l'vera~e Averfi
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Grant County PUD NO.2 SF Tariff 10
2 Hinson Power Company, LLC SF WSPP-C
3 Iberdrola Renewables, Inc.SF WSPP-C
4 Idaho Power Company SF WSPP-C
5 Idaho Power Company SF Tariff 12
6 Integry's Energy Service, Inc.SF WSPP-C
7 Intercontinental ICE SF ISDA
8 JP Morgan Ventures Energy SF Tariff 9
9 JP Morgan Ventures Energy SF ISDA
10 Macquarie Cook Power, Inc.SF WSPP-C
11 Macquarie Cook Power, Inc.SF WSPP-C
12 Modesto Irrigation District SF WSPP-C
13 Morgan Stanley SF ISDA
14 Morgan Stanley SF........ISDA
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.2
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) r=A Resubmission 04/1612010
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tarifs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQINon-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (9) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
4,835 4,835 1
2,880 69,200 69,200 2
434,552 16,458,261 16,458,261 3
20,413 685,627 685,627 4
54 1,922 1,922 5
4,000 157,100 157,100 6
13,536 13,536 7
81,000 2,414,870 2,414,870 8
84,168 84,168 9
67,147 2,329,272 2,329,272 10
50 50 11
13,298 422,306 422,306 12
397,644 15,764,322 15,764,322 13
-8,896 -8,896 14
0 0 0 0 0
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
FERC FORM NO.1 (ED. 12-90)Page 311.2
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera~e Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing ~vera~e Aver~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 NaturEner Glacier Wind Energy 1, LLC SF Tariff 9
2 NaturEner Glacier Wind Energy 1, LLC SF/.d/Tariff 9
3 NaturEner Glacier Wind Energy 1, LLC SF Tariff 9
4 NaturEner Glacier Wind Energy 1, LLC SF Tariff 9
5 NaturEner Power Watch, LLC SF Tariff 9
6 NaturEner Power Watch, LLC SF Tariff 12
7 NaturEner Power Watch, LLC SF Tarif 9
8 NaturEner Power Watch, LLC SF Tarif 9
9 NaturEner Power Watch, LLC SF Tariff 9
10 NaturEner Power Watch, LLC SF Tariff 9
11 Nexen Marketing U.S.A, Inc.SF WSPP-C
12 NorthWestem Energy LLC IF Tariff 10
13 NorthWestem Energy LLC IF Tariff 10
14 NorthWestem Energy LLC IF Tariff 9
Subtotal RO .,0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.3
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must tie subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on .
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
2,736 96,588 96,588 1
7,182 7,182 2
412,404 412,404 3
81,200 81,200 4
4,205 182,621 182,621 5
6 253 253 6
1,560 1,560 7
220,800 220,800 8
312,500 312,500 9
56,344 56,344 10
318 8,490 8,490 11
3,256,935 3,256,935 12
688,800 688,800 13
38,032 1,297,127 1,297,127 14
0 0 0 0 0
4,737,063 7,316,703 170,721 ,483 20,477,877 198,516,063
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
FERC FORM NO.1 (ED. 12-90)Page 311.3
Name of Respondent
Avista Corporation
This ~ort Is:
(1) ~An Original
(2) r"A Resubmission
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricit ( i.e., transactions involvng a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Date of Report
(Mo, Da, Yr)
04/16/2010
YearlPeriod of Report
End of 2009/Q4
Line Name of Company or Public AuthorityNo. (Footnote Affliations)
(a)
1 NorthWestern Energy LLC
2 NorthWestern Energy LLC
3 NorthWestern Energy LLC
4 NorthWestern Energy LLC
5 Okanogan County PUD
6 Pacific NW Generating Coop
7 PacifiCorp
8 PacifiCorp
9 PacifiCorp
10 PacifiCorp
11 Peaker LLC
12 Pend Oreile Public Utilty District
13 Pend Oreile Public Utilty District
14 Pend Oreile Public Utilty District
Statistical
Classif-
cation
(b)
SF
SF
LF
SF
SF
SF
SF
SFLF ..SF I. ...
LF ....... .
LF . .
LF
SF
FERC Rate
Schedule orTariff Number
(c)
WSPP-C
Tariff 12
Tariff 9
Tariff 10
WSPP-C
WSPP-C
WSPP-C
Actual Demand (MW)
Average Aver¡¡Qe
Monthly NCP Deman Monthly CfTDemand(e) (f)
AverageMonthly Biling
Demand (MW)
(d)
Tariff 12
Tariff 9
....,q1i.ri
Tariff 9
Tariff 10
Tariff 9
Tariff 9
Subtotal RO
Subtotal non-RO
Total
o
o
o
o
o
o
o
oo
FERC FORM NO.1 (ED. 12-90)Page 310.4
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/16/2010
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQlNon-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
151,013 5,431,652 5,431,652 1
55 1,804 1,804 2
7,734 240,851 240,851 3
331,936 331,936 4
16,641 579,605 579,605 5
2,310 67,985 .67,985 6
103,283 3,087,335 3,087,335 7
220 7,887 7,887 8
4,922 153,269 153,269 9
500 500 10
1,747,891 1,747,891 11
390,166 390,166 12
6,577 223,131 223,131 13
39,778 1,616,942 1,616,942 14
0 0 0 0 0
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
FERC FORM NO.1 (ED. 12-90)Page 311.4
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2)A Resubmission 04/1612010
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricit ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-ter service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly illng Avera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Pend Oreile Public Utilty District SF Tariff10
2 Portland General Electric Company SF WSPP-C
3 Portland General Electric Company SF Tariff 12
4 Portland General Electric Company SF ...290
5 Portland General Electric Company SF Tarif 10
6 Powerex SF WSPP-C
7 Powerex SF Tariff 9
8 Powerex SF Tariff 9
9 PPL EnergyPlus, LLC SF Tariff 10
10 PPL EnergyPlus, LLC SF WSPP-C
11 PPL EnergyPlus, LLC LF Tariff 9
12 Public Service of Colorado SF WSPP-C
13 Puget Sound Energy ILf.........Tarif 9
14 Puget Sound Energy SF WSPP-C
Subtotal RQ 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.5
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 0411612010
S LES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (6D-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j)(k)
57,434 57,43-4 1
58,695 2,619,691 2,619,691 2
49 1,935 1,935 3
525 525 4
350 350 5
407,256 15,319,901 15,319,901 6
78,930 78,930 7
16,800 16,800 8
271,095 271,095 9
30,091 958,923 958,923 10
17,577 547,390 547,390 11
1,200 55,000 55,000 12
22,499 700,659 700,659 13
143,111 5,149,085 5,149,085 14
0 0 0 0 0
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
FERC FORM NO.1 (ED. 12-90)Page 311.5
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/1612010
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricit (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authorit Statistical FERC Rate Averaße Actual Demand (MW)
Classif-Schedule or Monthly iIing Avera~e Aver~No.(Footnote Affliations)cation Tarif Number Demand (MW)Monthly NC Deman Monthly C mand
(a)(b)(c)(d)(e)(f)
1 Puget Sound Energy SF Tariff 12
2 Rainbow Energy Marketing SF WSPP-C
3 Redding, Cit of SF WSPP-C
4 Sacramento Municipal Utilty District SF WSPP-C
5 Sacramento Municipal Utility District SF Tariff 12
6 Sacramento Municipal Utility District LF WSPP-C
7 San Diego Gas & Electric Company SF WSPP-C
8 Seattle Cit Light SF WSPP-C
9 Seattle City Light SF Tariff 12
10 Sempra Energy Trading SF WSPP-C
11 Sempra Energy Trading SF ISDA
12 Shell Energy N.A.SF WSPP-C
13 Shell Energy N.A.SF Tariff 9
14 Sierra Pacific Power Company SF WSPP-C
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.6
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/16/2010
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accunting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f).. For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (6D-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
7 297 297 1
34,120 1,068,314 1,068,314 2
48 1,812 1,812 3
64,548 2,236,787 2,236,787 4
2 86 86 5
651,567 27,648,377 27,648,377 6
200 1,100 1,100 7
17,206 429,611 429,611 8
4 138 138 9
120,874 6,276,840 6,276,840 10
28,012 28,012 11
403,194 13,920,196 13,920,196 12
4,100 4,100 13
2,691 133,127 133,127 14
0 0 0 0 0
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
FERC FORM NO.1 (ED. 12-90)Page 311.6
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) r=A Resubmission 04/1612010
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricit (Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera~e Actual Demand (MW)
Classifi-Schedule or Monthly iIling Avera~e Avera~No.(Footnote Affliations)cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Sierra Pacific Power Company SF Tariff 12
2 Snohomish County PUD SF WSPP-C
3 Sovereign Power LF Tariff 10
4 Sovereign Power LF. ....d Tariff 9
5 Tacoma Power SF WSPP-C
6 Tacoma Power SF Tariff 10
7 The Energy Authority SF WSPP-C
8 TransAlta Energy Marketing SF WSPP-C
9 Turlock Irrigation District SF WSPP-C
10 Vaagen Brothers SF Tariff 8
11 IntraCompany Wheeling LF
12 IntraCømpao¥Gerieration LF
13 Revenue Adjustment AD
14
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.7
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/16/2010
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
48 1,728 1,728 1
3,820 113,615 113,615 2
97,382 97,382 3
11,973 413,788 413,788 4
3,266 61,906 61,906 5
400 400 6
4,238 130,335 130,335 7
114,201 3,153,359 3,153,359 8
12,800 454,510 454,510 9
5,179 5,179 10
-17,881,243 17,881,243 11
686,128 686,128 12
343 17,741 17,741 13
14
0 0 0 0 0
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
4,737,063 7,316,703 170,721,483 20,477,877 198,516,063
FERC FORM NO.1 (ED. 12-90)Page 311.7
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2010
ELE TRIC OPERATION AND MAINTENA CE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forNo Current Year. (a) (b)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineerin
5 (501) Fuel
6 (502) Steam Expenses
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expense$
10 (506) Miscellaneous Steam Power Expenses
11 507) Rents
12 509) Allowances
13 TOTAL 0 eration (Enter Total of Lines 4 thru 12)
14 Maintenance
15 (510) Maintenance Supervision and Engineerin
16 (511) Maintenance of Structures
17 512) Maintenance of Boiler Plant
18 (513) Maintenance of Electric Plant
19 514 Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and En ineerin
25 (518) Fuel
26 (519 Coolants and Water
27 (520) Steam Expenses
28 521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Ex enses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and En ineerin
36 (529) Maintenance of Structures
37 530 Maintenance of Reactor Plant E ui ment
38 (531) Maintenance of Electric Plant
39 (532 Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power Entr tot lines 33 & 40)
42 C. H draulic Power Generation
43 0 eration
44 535) Operation Supervision and En ineerin
45 536) Water for Power
46 (537) H draulic Expenses
47 (538 Electric Expenses
48 (539) Miscellaneous Hydraulic Power Generation Expenses
49 (540) Rents
50 TOTAL Operation (Enter Total of Lines 44 thru 49)
51 C. H draulic Power Generation (Continued
52 Maintenance
53 541 Mainentance Supervision and En ineerin
54 542 Maintenance of Structures
55 (543) Maintenance of Reservoirs, Dams, and Waterwa s
56 (544 Maintenance of Electric Plant
57 545 Maintenance of Miscellaneous H draulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses-H draulic Power (tot of lines 50 & 58
Amount forPrevious Year
(c)
514,450 353,838
22,358,344 28,776,474
2,614,109 1,880,633
699,318 814,258
2,783,706 3,455,151
29,773 38,367
28,999,700 35,318,721
500,139 461,747
546,526 526,317
5,457,086 4,876,984
2,565,316 544,537
937,372 637,092
10,006,439 7,046,677
39,006,139 42,365,398
2,278,227
815,150
4,390,300
5,604,151
630,038
6,068,605
19,786,471
1,642,209
744,841
3,209,339
4,724,140
984,206
802,071
12,106,806
249,607
343,445
646,541
1,937,827
1,835,745
5,013,165
24,799,636
302,771
312,861
662,450
2,164,716
294,574
3,737,372
15,844,178
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/16/2010
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ~No.urrent ear Previous ear
(a)(b) (c)
60 D. Other Power Generation
61 Operation
62 (546) Ooeration Supervision and Engineerino 846,899 1,650,998
63 547) Fuel 68,656,659 107,175,030
64 (548) Generation Expenses 2,215,456 1,666,082
65 (549) Miscellaneous Other Power Generation Expenses 456,697 455,207
66 550) Rents -33,811 33,433
67 TOTAL Operation (Enter Total of lines 62 thru 66)72,141,900 110,980,750
68 Maintenance
69 (551) Maintenance Supervision and Enoineering 775,889 423,483
70 (552) Maintenance of Structures 1,850 4,186
71 (553) Maintenance of Generating and Electric Plant 1,893,421 4,920,956
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 100,412 114,800
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)2,771,572 5,463,425
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)74,913,472 116,44,175
75 E. Other Power Supply Expenses
76 (555) Purchased Power 303,784,778 276,853,230
77 (556) Svstem Control and Load Dispatching 528,673 500,980
78 (557) Other Expenses 69,198,479 78,800,960
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)373,511,930 356,155,170
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79)512,231,177 530,808,921
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering 2,436,974 2,227,450
84 (561) Load Dispatching 2,224,918 1,981,275
85 (561.1) Load Disoatch-Reliabilty
86 (561.2) Load Dispatch-Monitor and Operate Transmission Svstem
87 I (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliabilty, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies
92 (561.8) Reliabilitv, Planning and Standards Development Services
93 I (562) Station Expenses 190,291 252,115
94 (563) Overhead Lines Expenses 543,042 505,160
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricitv bv Others 13,350,741 13,632,001
97 (566) Miscellaneous Transmission Expenses 1,387,100 1,312,796
98 (567) Rents 152,055 100,620
99 TOTAL Operation (Enter Total of lines 83 thru 98)20,285,121 20,011,417
100 Maintenance
101 (568) Maintenance Suoervision and Engineering 566,082 591,365
102 (569) Maintenance of Structures 330,766 279,425
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Softare
105 (569.3) Maintenance of Communication Equipment
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 1,127,999 1,237,393
108 (571) Maintenance of Overhead Lines 1,528,641 1,226,863
109 (572) Maintenance of Underground Lines 17,566 1,311
110 (573) Maintenance of Miscellaneous Transmission Plant 38,785 7,209
111 TOTAL Maintenance (Total of lines 101 thru 110)3,609,839 3,343,566
112 TOTAL Transmission Exoenses (Total of lines 99 and 111)23,894,960 23,354,983
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ~No.urrent ear Previous ear
(a)(b) . (c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Faciltation
117 (575.3) Transmission Riohts Market Faciltation
118 (575.4) Capacity Market Faciltation
119 (575.5) Ancilary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Faciltation, Monitorino and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Softare
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Reoional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Enoineering 1,367,048 1,391,231
135 (581) Load Dispatching
136 (582) Station Expenses 546,953 621,675
137 (583) Overhead Line Expenses 1,577,717 1,975,815
138 (584) Underground Line Expenses 710,346 896,606
139 (585) Street Lighting and Signal System Expenses 218,441 194,939
140 (586) Meter Expenses 1,619,021 1,308,218
141 (587) Customer Installations Expenses 861,022 825,366
142 (588) Miscellaneous Expenses 5,871,255 5,097,414
143 (589) Rents 375,764 191,442
144 TOTAL Operation (Enter Total of lines 134 thru 143)13,147,567 12,502,706
145 Maintenance
146 (590) Maintenance Supervision and Enoineerino 1,326,210 1,371,668
147 (591) Maintenance of Structures 280,729 294,513
148 (592) Maintenance of Station Equipment 1,030,655 750,947
149 (593) Maintenance of Overhead Lines 6,823,635 7,983,419
150 (594) Maintenance of Underground Lines 1,067,148 1,059,209
151 (595) Maintenance of Line Transformers 1,040,344 678,925
152 (596) Maintenance of Street Liohting and Sional Svstems 638,654 610,966
153 I (597) Maintenance of Meters 160,883 145,069
154 (598) Maintenance of Miscellaneous Distribution Plant 315,281 503,563
155 TOTAL Maintenance (Total of lines 146 thru 154)12,683,539 13,398,279
156 TOTAL Distribution Expenses (Total of lines 144 and 155)25,831,106 25,900,985
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 567,832 490,861
160 (902) Meter Reading Expenses 2,624,185 2,313,137
161 I (903) Customer Records and Collection Expenses 8,243,568 7,490,538
162 (904) Uncollectible Accounts 2,735,983 1,927,667
163 (905) Miscellaneous Customer Accunts Expenses 244,871 147,464
164 TOTAL Customer Accunts Expenses (Total of lines 159 thru 163)14,416,439 12,369,667
FERC FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2010
ELECTRIC OPERATION AND MAINTENANCE PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt Amount forNo Current Year. (b)
506,252 424,827
114,294 128,150
307,957 213,550
928,503 766,527
22,474,374 19,181,918
3,928,835 3,782,093
49,301 38,836
11,313,636 10,997,229
1,283,269 1,015,509
3,543,277 2,968,505
1,053,264 1,186,191
6,704 5,950
4,999,707 4,783,704
264,628 4,017
3,129,106 3,198,612
393,144 590,566
thru 193)52,340,643 47,675,458
7,960,364 7,319,496
60,301,007 54,994,954
663,266,859 665,007,310
YearlPeriod of Report
End of 2009/04
Ampunt forPrevious Year
(c)
25,449,316
67,743
146,608
25,663,667
16,553,310
112,666
145,297
16,811,273
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/16/2010
PU~CJ1JfED POWER chAccu~t 555)n u ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Qr üil
) .......
.......SF ISDA...
2 BP Energy Comp IF WSPP
3 BP Energy Comp SF WSPP
4 BP Energy Comp SF ISDA
5 Barclays Bank PLC SF WSPP
6 Barclays Bank PLC SF ISDA
7 Black Creek Hydro LU FERC#1
8 Black Hils Power SF WSPP
9 Bonnevile Power Administration LF WNP#3Agr.
10 Bonnevile Power Administration SF WSPP
11 Bonneville PÓWéf Administration EX PNCA
12 Bonnevile Power Administration SF Tariff #8
13 Bonnevile Power Adrninistration OS BPAOATI
14 Bonneville Power Administration SF BPAOATI
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) ñA Resubmission 04/16/2010
cc~t.~~~L\ (ContinUed),,~, .. '71iiciudlng power ex anges)
AD - for out-of-period adjustment. Use this code for any accunting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)0)(k (I)(m)
13,997,921 13,997,921 1
219,OOC 7,555,50C 7,555,500 2
249,03'13,327,65€13.327,656 3
4
524,36C 32,302,59€32,302,596 5
1,589,532 1,589,532 6
4,17.138,78E 138,789 7
2,20C 61,75C 61,750 8
393,71 14,078,03C 14,078,030 9
106,2C 3,364,83'3,364,834 10
3,050 2,550 14,42!24,660 39,089 11
33,67~1,100,82 1,100,827 12
2,190 2,190 13
7,99~316,25 -24,109 292,148 14
7,373,956 688,110 689,010 11,824,462 273,902,860 18,057,458 303,784,78C
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) rïA Resubmission 04/1612010
PU~C~AcHED POWER hAccunt 5 5)( nc u ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date ofthe contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacit, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Cargil Power Markets, LLC SF WSPP
2 Chelan County PUD NO.1 LU Rocky Reach
3 Chelan County PUD NO.1 SF WSPP
4 City of Spokane LU PURPA
5 Clatskanie Peoples PUD SF WSPP
6 Constellation Energy Commodities Group SF WSPP
7 Douglas County PUD NO.1 LU Wells
8 Douglas County PUD NO.1 LU Wells Settlement
9 Douglas County PUD NO.1 IF Wells
10 Douglas County PUD NO.1 SF WSPP
11 po~ÎisêQnntyPt.ONa.1 EX 305
12 Eagle Energy Partners SF WSPP
13 Endure Energy SF WSPP
14 Eugene Water & Electric Board SF WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
,(2) DA Resubmission 04/16/2010
. v.... 'n ;\1 ccu~t.~~~i\ (ContlnUeCl)Inc uding power exc anges)
AD - for out-of-period adjustment. Use this code for any accunting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tari, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identifed in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)0)(k (I)(m)
13,86f 454,911 454,918 1
150,36'1 1,657,771 1,657,777 2
3,607 478,3H 478,318 3
45,267 1,792,49'1,792,493 4
8,971 227,23E 227,238 5
96,656 4,477,82 4,477,821 6
249,72 1,411,52E 1,411,526 7
19,30f 364,521 364,527 8
11,202,012 11,202,012 9
19,15f 654,891 654,897 10
109,860 110,011 1,511,39,;-6,708 1,504,685 11
80C 30,90C 30,900 12
9,35~303,00~303,003 13
11,78l 303,96E 303,966 14
7,373,956 688,110 689,010 11,824,462 273,902,86C 18,057,458 303,784,78C
FERC FORM NO.1 (ED. 12-90)Page 327.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) r"A Resubmission 04/1612010
PU~C~AdfED POWER hAccunt 5 5)( nc u ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e.. transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be place in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tarif Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Fortis Energy Mkt SF WSPP
2 Ford Hydro Limited Partnership LU PURPA
3 Grant County PUD NO.2 LU Wanapum
4 Grant County PUD NO.2 LU Priest Rapids
5 Grant County PUD NO.2 LU PR Displacement
6 Grant County PUD NO.2 SF WSPP
7 Grant County PUD NO.2 SF WSPP
8 Hydro Technology Systems LU PURPA
9 Idaho Power Company SF WSPP
10 Inland Power & Light Company RO 208
11 Integrys Energy Services SF WSPP
12 Interct)ntinertalEìalange H.C SF ISDA
13 J P Morgan Ventures Energy SF WSPP
14 Jim White LU PURPA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.2
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
.. "' ccou~t.~~~L (ContinUed)'('ncluding power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariff or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column U), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)m (k (I)(m)
4,00(140,94C 140,940 1
2,35~114,25~114,259 2
268,84~4,988,90f 4,988,908 3
151,09A 4,998,81€4,998,816 4
193,981 .5,332,75¿5,332,754 5
25,131 733,65f 733,658 6
250 250 7
7,65E 364,881 364,881 8
11,QC 275,77.:275,773 9
11 C 6,69.:6,693 10
40C 17,20C 17,200 11
-71,834 -71,834 12
16,06.0 497,13~497,139 13
98C 90,08¿90,084 14
7,373,956 688,110 689,010 11,824,462 273,902,860 18,057,458 303,784,78C
FERC FORM NO.1 (ED. 12-90)Page 327.2
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2)A Resubmission 04/1612010
PU~C~eHED POWER W'ccunt 5 5)( nc u ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 John Day Hydro LU PURPA
2 Kalich, Clint LU PURPA
3 Macquarie Cook Power SF WSPP
4 Mirant Energy Trading LU WSPP
5 Morgan Stanley Capital Group IF WSPP
6 Morgan Stanley Capital Group SF WSPP
7 Morgal' Stanley Capitäl Group SF ISDA
8 NaturEilerPower Watch SF WSPP
9 Northpoint Energy Solutions SF WSPP
10 NorthWestem Energy LLC SF WSPP
11 Okanogan County PUD NO.1 SF WSPP
12 PPL Energy Plus SF WSPP
13 PPM Energy LU PPM Energy
14 PPM Energy SF WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.3
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
ccuHt.~~~i\ ((,ontinueo¡
.. .". 'liricluding power exc anges)
AD - for out-of-period adjustment. Use this code for any accunting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (6o-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)u)(k (I)(m)
2,14~90,02~90,025 1
1 2
10,4&4 357,23 357,237 3
40C 18,30C 18,300 4
657,00C 20,191,04C 20,191,040 5
187,661 10,156,57~10,156,573 6
1,500,540 1,500,540 7
136,560 136,560 8
10,40C 355,16C 355,160 9
47,70~1,660,86A 1,660,864 10
39,59~1,240,52 1,240,523 11
1,485,71E 47,352,15f 47,352,158 12
70,55~2,845,92 2,845,927 13
441,77~16,622,65E 16,622,656 14
7,373,956 688,110 689,010 11,824,462 273,902,860 18,057,458 303,784,78C
FERC FORM NO.1 (ED. 12-90)Page 327.3
Name of Respondent This Re ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) .~An Original (Mo, Da, Yr)End of 2009/04
(2)A Resubmission 04116/2010
PU~CJldfED POWER hAccount 5 5)
(n u ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature,
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 PacifiCorp SF WSPP
2 Pacific NW Gen Corp SF WSPP
3 Pend Oreile County PUD NO.1 SF Pend 0'
4 Pend Oreile County PUD No. 1 SF Pend 0'
5 Phillps Ranch LU PURPA
6 Portland General Electric Company EX 304
7P9~'al'~~~her~IEløçtrjç goìiariy EX 178
8 Portland General Electric Company SF WSPP
9 Potlatch Corporation LU PURPA
10 Powerex Corp SF WSPP
11 Powerex Corp SF WSPP
12 Puget Sound Energy SF WSPP
13 Rainbow Energy Marketing Corp SF WSPP
14 Sacramento Municipal Utilty District SF WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.4
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010
ccuH!.~~~i\ (contlnUeCl)
~ .~. 'liñeluding power exc anges)
AD - for out-of-period adjustment. Use this code for any accunting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered ($)($~
\'1
of Settlement ($)
(g)(h)(i)u)(k (m)
74,36 2,355,16!2,355,169 1
2,70.59,921 59,921 2
6,941 91,30~91,303 3
102,04~17,037 16,975 2,952,09E 220 2,952,318 4
4~2,85€2,856 5
9,843 9,841 6
438,720 439,290 -19,170 -19,170 7
69,30€2,548,121 2,548,127 8
452,31 19,413,44€19,413,446 9
81,10 4,202,15€4,202,156 10
622,200 622,200 11
39,571 1,350,95C 1,350,95C 12
85,071 2,818,35~2,818,359 13
8,92~250,58E 250,588 14
7,373,956 688,110 689,010 11,824,462 273,902,860 18,057,458 303,784,78C
FERC FORM NO.1 (ED. 12-90)Page 327.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/1612010
PU~C~AcHED POWER hAccunt 5 5)
( nc u ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilateraiiy get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
II
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 San Diego Gas & Electric SF WSPP
2 Seattle City Light SF WSPP
3 Seattle Cit Light EX WSPP
4 Sempra Energy Trading SF WSPP
5 Sheep Creek Hydro LU PURPA
6 Shell Energy SF WSPP
7 Shell Energ SF ISDA
8 Sierra Pacific Power Company SF WSPP
9 Snohomish County PUD No. 1 SF WSPP
10 Sovereign Power IF Sovereign
11 Stimson Lumber IU PURPA
12 Tacoma Power SF WSPP
13 Tacoma Power SF WSPP
14 The Energy Authority SF'WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.5
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) riA Resubmission 04/1612010
ccou~t.~~~t. (ContinUed)"rJiicludlng power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.Received Delivered ($)($~
~'l
of Settlement ($)
(g)(h)(i)ü)(k (m)
7!75 1
32,21E 857,12€857,126 2
109,600 109,600 1,535,04C 1,535,040 3
134,161 7,461,051 7,461,057 4
5,825 241,514 241,514 5
204,04~8,101,271 8,101,271 6
1,044,168 1,044,168 7
1,02C 40,70C 40,700 8
9,1n 310,38~310,385 9
3,325 60,96C 60,96C 10
36,97:;1,865,40~1,865,401:11
27,93C 670,38C 670,38C 12
7~75 13
13,31:;419,32~419,328 14
7,373,956 688,110 689,010 11,824,462 273,902,860 18,057,458 303,784,78C
FERC FORM NO.1 (ED. 12-90)Page 327.5
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) DA Resubmission 04/1612010
PU~CHAJlED POWER hAccunt 5 5)(nclu ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same a,s, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliability of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 TransAlta Energy Marketing SF WSPP
2 IntraCompany Generation Services OS OATI
3 gthêt*lnåa\Te~nfiiit~rçnlinge EX
4 Other - Inadvertent Interchange EX
5
6
7
8
9
10
11
12
13
14
Total
FERC FORM NO.1 (ED. 12-90)Page 326.6
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/16/2010
ccoUHt.~~~L (Continued)(Including poWer exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tarif, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariff or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ($)($~
\'1
of Settlement ($)
(g)(h)(i)u)(k (m)
178,52.1 11,227,421 11,227,421 1
686,12€686,128 2
-116,512 -116,512 3
743 4
5
6
7
8
9
10
11
12
13
14
7,373,956 688,110 689,010 11,824,462 273,902,860 18,057,458 303,784,78(
FERC FORM NO.1 (ED. 12-90)Page 327.6
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
i t:9K v.' '!~ ':.~~ ccunt 456.1 )(Includiiia transactions referred to as 'wheelin ')
1. Report all transmission of elecricity, i.e., wheeling, provided for other electnc utilties, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authori that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authorit that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classifcation code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Vaagen Brothers Vaagen Brothers Idaho Power Company LFP
2 PacifiCorp PacifiCorp PacifiCorp LFP
3 Seattle Cit Light Seattle City Light"Bonnevile Power Administration LFP
4 Tacoma City Light Tacoma City Light Bonnevile Power Administration LFP
5 Grant County Public Utilty Dist Grant County Public Utilty Dist Grant County Public Utilty Dist LFP
6 Spokane Indian Tribes Bonnevile Power Administration Spokane Indian Tribes LFP
7 USBR Bonnevile Power Administration East Greenacres LFP
8 Consolidated Irrigation District Bonnevile Power Administration Consolidated Irrigation District LFP
9 Bonnevile Power Administration Bonnevile Power Administration Bonnevile Power Administration FNO
10 Cit of Spokane City of Spokane Puget Sound Energy LFP
11 Grant County Public Utilty Dist Bonnevile Power Administration NorthWestern Montana LFP
12 Bonnevile Power Administration Bonnevile Power Administration Idaho Power Company NF
13 Bonnevile Power Administration Bonnevile Power Administration Idaho Power Company SFP
14 Idaho Power Company Grant County Public Utilty Dist Idaho Power Company NF
15 Idaho Power Company Puget Sound Energy Idaho Power Company NF
16 Idaho Power Company Avista Corporation Bonnevile Power Administration NF
17 Idaho Power Company Idaho Power Company Bonnevile Power Administration NF
18 Idaho Power Company Bonnevile Power Administration Idaho Power Company NF
19 Idaho Power Company Idaho Power Company Chelan Public Utilty District NF
20 Idaho Power Company Idaho Power Company Puget Sound Energy NF
21 Idaho Power Company Idaho Power Company Grant County Public Utilit Dist NF
22 Idaho Power Company Chelan Public Utilty District Idaho Power Company NF
23 Idaho Power Company Bonnevile Power Administration Idaho Power Company SFP
24 Idaho Power Company NorthWestern Montana Bonnevile Power Administration SFP
25 Idaho Power Company Idaho Power Company Puget Sound Energy SFP
26 Idaho Power Company Idaho Power Company Bonnevile Power Administration SFP
27 Idaho Power Company Chelan Public Utilty District Idaho Power Company SFP
28 Idaho Power Company Grant County Public Utilty Dist Idaho Power Company SFP
29 NorthWestem Energy NorthWestem Montana Bonnevile Power Administration NF
30 NorthWestem Energy NorthWestem Montana Idaho Power Company SFP
31 PacifiCorp PacifCorp Bonnevile Power Administration NF
32 PacifiCorp NorthWestem Montana PacifiCorp NF
33 PacifiCorp Idaho Power Company PacifiCorp NF
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010
l.!" t:Lt:(, i ~11,1I T,V' ccun. ..",u/\vontlnUeO¡(Including transactions reffered to as 'wlieelina')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was d~livered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
FERC No. 228 Colvile Substation Lolo-Oxbow 230 kv 4 15,885 15,88E 1
FERC No. 182 Lolo-Oxbow 230 kv Dry Gulch 20 53,857 53,85 2
FERC Trf NO.8 Chelan-Stratford 115 Stratford 115kV SS 192,178 192,17E 3
FERC Trf NO.8 Chelan-Stratford 115 Stratford 115kV SS 192,178 192,11f 4
FERC No. 104 Larson Substation Round Lake/Coulee Cy 25 101,397 101,39 5
FERC Trf NO.8 Sunset Westside 2 3,141 3,141 6
FERC Trf NO.8 Bell Substation East Greenacres 3 3,129 3,12~7
FERC Trf NO.8 Bell Substation Consolidated 4 6,299 6,299 8
FERC Trf NO.8 1,852,995 1,852,995 9
FERC No. 155 Sunset-Westside 115k Westside 23 133,987 133,981 10
FERC Trf NO.8 41,078 41,0713 11
FERC Trf NO.8 65,556 65,55€12
FERC Trf NO.8 17,488 17,4813 13
FERC Trf NO.8 2,400 2,40C 14
FERC Trf NO.8 415 41~15
FERC Trf NO.8 800 80C 16
FERC Trf NO.8 62,046 62,04€17
FERC Trf NO.8 21,126 21,12€18
FERC Trf NO.8 775 775 19
FERC Trf NO.8 1,450 1,45C 20
FERC Trf NO.8 400 40C 21
FERC Trf NO.8 79 75 22
FERC Trf NO.8 223,209 223,205 23
FERC Trf NO.8 3,680 3,68C 24
FERC Trf No. 8 3,994 3,99.t 25
FERC Trf NO.8 75,535 75,53E 26
FERC Trf NO.8 400 40C 27
FERC Trf NO.8 520 52C 28
FERC Trf NO.8 91 91 29
FERC Trf NO.8 30
FERC Trf NO.8 292 29~31
FERC Trf NO.8 1,972 1,97~32
FERC Trf NO.8 50 5C 33
,34
81 3,225,567 3,225,561
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent This ~rrt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) A Resubmission 04/1612010
. u.t' T i ~li ccun wi ontìnued)
(Includina transactons reffred to as 'w eeliõãi)
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (i), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and u) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.,
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)t Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
61,864 15,885 19,481 97,230 1
206,460 206,460 2
133,527 133,527 3
133,527 133,527 4
27,381 27,381 5
14,583 14,583 6
16,533 16,533 7
35,448 35,448 8
5,333,884 5,333,884 9
127,506 32,088 159,594 10
167,900 167,900 11
227,652 227,652 12
79,84 79,846 13
9,600 9,600 14
1,702 1,702 15
3,200 3,200 16
263,834 263,834 17
85,332 85,332 18
3,385 3,385 19
6,332 6,332 20
1,747 1,747 21
316 316 22
1,033,899 1,033,899 23
15,714 15,714 24
14,479 14,479 25
201,382 201,382 26
1,450 1,450 27
1,885 1,885 28
564 564 29
36,456 36,456 30
4,562 4,562 31
30,005 30,005 32
781 781 33
34
8,122,208 1,002,697 51,569 9,176,474
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent This 'O0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010
.UI' cLI;l, i ..iv) IT.. i~~ccount 400.1 J
(Including transactions referred to as 'wheelin ')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilties, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accunting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classif-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 PacifiCorp'PacifiCorp Idaho Power Company NF
2 PacifiCorp PacifiCorp Bonnevile Power Administration SFP
3 Iberdrola Renewables, Inc.PacifiCorp Bonnevile Power Administration NF
4 Iberdrola Renewables, Inc.Idaho Power Company Bonnevile Power Administration NF
5 Powerex NorthWestern Montana Bonnevile Power Administration NF
6 Powerex Idaho Power Company Bonnevile Power Administration NF
7 Powerex Bonnevile Power Administration Idaho Power Company NF
8 Puget Sound Energy NorthWestern Montana Bonnevile Power Administration NF
9 Puget Sound Energy Bonnevile Power Administration Idaho Power Company NF
10 Puget Sound Energy NorthWestern Montana Bonnevile Power Administration SFP
11 Portland General Electric NorthWestern Montana Portland General Electric NF
12 Portland General Electric NorthWestern Montana Portland General Electric SFP
13 Morgan Stanley Capital Group Idaho Power Company Avista Corporation NF
14 Morgan Stanley Capital Group Idaho Power Company Bonnevile Power Administration NF
15 Morgan Stanley Capital Group NorthWestern Montana Bonnevile Power Administration NF
16 Sierra Pacific Power Company Bonnevile Power Administration Idaho Power Company NF
17 Sierra Pacific Power Company Puget Sound Energy Idaho Power Company NF
18 Cargil Power Markets NorthWestern Montana Bonnevile Power Administration NF
19 Cargil Power Markets .NorthWestern Montana Avista Corporation NF
20 Cargil Power Markets Idaho Power Company Avista Corporation NF
21 Cargil Power Markets Idaho Power Company Bonnevile Power Administration NF
22 Cargil Power Markets Idaho Power Company Grant County Public Utilty Dist NF
23 Cargil Power Markets Bonnevile Power Administration Idaho Power Company NF
24 Cargil Power Markets Bonnevile Power Administration NorthWestern Montana NF
25 Cargil Power Markets Idaho Power Company Chelan Public Utilty District NF
26 Cargil Power Markets Bonnevile Power Administration Idaho Power Company SFP
27 Cargil Power Markets Idaho Power Company Bonnevile Power Administration SFP
28 Cargil Power Markets NorthWestern Montana Avista Corporation SFP
29 Cargil Power Markets NorthWestern Montana Grant County Public Utilty Dist SFP
30 Rainbow Energy Marketing Corp Idaho Power Company Bonneville Power Administration NF
31 Rainbow Energy Marketing Corp Idaho Power Company Bonneville Power Administration SFP
32 Coral Power NorthWestern Montana Chelan Public Utilty District NF
33 Coral Power Bonnevile Power Administration Idaho Power Company NF
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.1
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2)A Resubmission 04/1612010
i OF T FgR ~ , , ,'-, '.'" ,V' ccount 456)((;ontinued)
(Includina transactons reffered to as 'wlìeeliñei:f
5. In column (e), identify the FERC Rate Schedule or Tari Number, On separate lines, list all FERC rate scedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identifcation for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specifed in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours -regawatt Hours No.Tariff Number Designation)Designation)(MW Received Delivered
(e)(f)(g)(h)(i)0)
FERC Trf NO.8 3,039 3,03!1
FERC Trf NO.8 2
FERC Trf NO.8 449 44E 3
FERC Trf NO.8 400 40C 4
FERC Trf NO.8 1,820 1,82C 5
FERC Trf NO.8 6,154 6,154 6
FERC Trf NO.8 2,615 2,61E 7
FERC Trf NO.8 8,214 8,214 8
FERC Trf NO.8 15 1 E 9
FERC Trf NO.8 2,512 2,51~10
FERC Trf NO.8 5,281 5,281 11
FERC Trf NO.8 1,076 1,QE 12
FERC Trf NO.8 151 151 13
FERC Trf NO.8 1,106 1,10E 14
FERC Trf NO.8 125 12E 15
FERC Trf NO.8 5,384 5,38¿16
FERC Trf NO.8 14 1 17
FERC Trf NO.8 1,868 1,861 18
FERC Trf NO.8 402 40 19
FERC Trf NO.8 400 401 20
FERC Trf NO.8 602 60 21
FERC Trf No. 8 192 19 22
FERC Trf NO.8 914 91'23
FERC Trf NO.8 529 52!24
FERC Trf NO.8 198 191 25
FERC Trf NO.8 400 401 26
FERC Trf NO.8 600 601 27
FERC Trf NO.8 1,198 1,191 28
FERC Trf NO.8 432 43~29
FERC Trf NO.8 2,400 2,40C 30
FERC Trf NO.8 4,650 4,65C 31
FERC Trf No. 8 4,968 4,96f 32
FERC Trf NO.8 760 76C 33
34
81 3,225,567 3,225,561
FERC FORM NO.1 (ED. 12-90)Page 329.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) t=A Resubmission 04/16/2010
i , u.t I:LI:l, i KIl,l i Y i-YK L! i, HI:K!= ,~~ccount 456) (ContinUed)
(Includina transactions reffered to as 'w eeling"f
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (i), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and u) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
47,476 47,476 1
14,858 14,858 2
8,568 8,568 3
1,600 1,600 4
8,996 8,996 5
26,658 26,658 6
11,026 11,026 7
32,920 32,920 8
60 60 9
3,600 3,00 10
23,516 23,516 11
4,450 4,450 12
634 634 13
4,646 4,646 14
500 500 15
23,015 23,015 16
53 53 17
7,052 7,052 18
1,608 1,608 19
1,634 1,634 20
2,458 2,458 21
784 784 22
3,687 3,687 23
2,189 2,189 24
792 792 25
1,615 1,615 26
1,615 1,615 27
3,230 3,230 28
1,551 1,551 29
9,600 9,600 30
12,460 12,460 31
20,493 20,493 32
3,293 3,293 33
34
8,122,208 1,002,697 51,569 9,176,474
FERC FORM NO.1 (ED. 12-90)Page 330.1
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/1612010
(Includino . J:9R - ':'nQo ccunt 456.1)transactons referred to as 'wheelin ')
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifing facilties, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authori. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authorit)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Coral Power NorthWestem Montana Bonnevile Power Administration NF
2 Coral Power NorthWestem Montana Grant County Public Utility Dist NF
3 Coral Power Idaho Power Company Chelan Public Utilty District NF
4 Coral Power Idaho Power Company Bonnevile Power Administration NF
5 PPL Energy Plus Bonnevile Power Administration NorthWestern Montana NF
6 PPL Energy Plus Avista Corporation NorthWestern Montana NF
7 PPL Energy Plus NorthWestem Montana Bonnevile Power Administration NF
8 PPL Energy Plus NorthWestern Montana Idaho Power Company NF
9 PPL Energy Plus NorthWestem Montana PacifiCorp SFP
10 TransAlta Energy Marketing US NorthWestern Montana Bonneville Power Administration NF
11 NaturEner USA NorthWestern Montana Bonnevile Power Administration NF
12 NaturEner USA Bonnevile Power Administration NorthWestern Montana SFP
13 NaturEner USA NorthWestem Montana Bonnevile Power Administration SFP
14 The Energy Authorit Bonnevile Power Administration NorthWestern Montana NF
15 The Energy Authority NorthWestern Montana Bonneville Power Administration NF
16 Grant County Public Utilty Dist NorthWestern Montana Bonnevile Power Administration NF
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.2
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010~r i-9K l.! ,.., ,.vy ccun ontinueo)- (Including transactions reffered to as 'wlieeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identifcation for where energy was received as specified in the contract. In column
(g) report the designation for the substation. or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
FERC Trf NO.8 252 25.1
FERC Trf NO.8 35 3~2
FERC Trf NO.8 203 20 3
FERC Trf NO.8 335 33~4
FERC Trf NO.8 71 71 5
FERC Trf NO.8 6
FERC Trf NO.8 160 16C 7
FERC Trf NO.8 390 39C 8
FERC Trf NO.8 600 60C 9
FERC Trf NO.8 103 10.10
FERC Trf NO.8 2,364 2,36'11
FERC Trf NO.8 7,791 7,791 12
FERC Trf NO.8 31,780 31,78C 13
FERC Trf NO.8 881 881 14
FERC Trf NO.8 8 i 15
FERC Trf NO.8 43,324 43,32'16
17
18
.19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
81 3,225,567 3,225,567
FERC FORM NO.1 (ED. 12-90)Page 329.2
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
! u.i ELECTI'I\,11 T i-yl' \. ccuht 456) (Continued)(Includina transactions reffered to as 'wfieeliñCl¡)
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
861 861 1
187 187 2
1,084 1,084 3
1,438 1,438 4
284 284 5
200 200 6
640 640 7
1,560 1,560 8
1,615 1,615 9
412 412 10
6,216 6,216 11
92,465 92,465 12
341,025 341,025 13
3,524 3,524 14
32 32 15
88,104 88,104 16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
8,122,208 1,002,697 51,569 9,176,474
FERC FORM NO.1 (ED. 12-90)Page 330.2
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FJA Resubmission 04/16/2010
TRANS~ ISSION OF ELECTRICITY BY OTHE S (Accunt 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or elecricity provided by other electric utilties, cooperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'i EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-MagaWatt-l,~mano ~nergy JJtner Total Cost ofliourslioursChar?eS Char?eS Char?eS TransæssionAuthority (Footnote Affliations)Classification Received Delivered ($($($
(a)(b)(c)(d)(e)(f)(0)
1 Bonnevile Power Admin LFP 1,173,079 1,173,079
.- '... --_... _. .,' '.....
1,142,002 8,431,5702 BoohevilePower Admin LFP 7,289,568
3 Bonnevile Power Admin LFP 788,931 788,931
4 BoonevHlePòerÄdmin FNS 1,m,855 327,687 1,505,542
5 BönêvilePoAdmii¡
...
OS 24,360 24,360
6 Bonnevile Power Admin SFP
7 BornevillePower Admin ..NF 39,526 39,526 170,201 -1,305 168,896
8 GrantPUD LFP 45,222 12,661 57,883
9 Kootenai Electic Coop LFP
10 Northem Lights LFP 140,006 140,006
11 NortWestern Energy NF 27,643 27,643 226,163 226,163
12 Nortwestern Energy SFP
13 Portland General Elec LFP 646,608 25,032 671,640
14 Portand General Elec NF
15 Puget Sound Energy NF
16 Rainbo Energy Mkt NF
TOTAL 119,73 119,737 11,261,269 .584,067 1,505,405 13,350,741
FERC FORM NO. 1/3-0 (REV. 02-04)Page 332
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010
TRANSMISSION OF ELECTRICITY BY OTHE S (Accunt 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bils or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'y EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawau-hI~manlJ !;nergy ,ymer Total Cost ofliouJSIioursChar?eS Char?eS Char?eS Trans~tsionAuthority (Footnote Affliations)Classification Received Delivered ($($($(a)(b)(c)(d)(e)(f)(g)
1 Seatte City Light NF 18,843 18,843 28,265 28,265
2 Snohomish PUD NF
3 Tacoma Power NF 33,725 33,725 134,406 134,406
4
5
6
7
8
9
10
11
12
13
14
15
16
TOTAL 119,73 119,737 11,261,269 584,067 1,505,405 13,350,741
FERC FORM NO. 1/3-0 (REV. 02-04)Page 332.1
Name of Respondent This 'f0rt Is:Date of Rep'ort YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) 0 A Resubmission 04/1612010
MISCELLANEOUS GENERA EXPENSES (Account 930.2) (ELECTRIC)
Line Descriltion Amount
No.(a (b)
1 Industry Association Dues 519,077
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 124,584
5 Oth Expn =-=5,000 show purpose, recipient, amount. Group if 0( $5,000
6 Miscellaneous General Expenses ......1.167,539
7 Community Relations 634,630
8 Education and Informational 29,020
9 Other Miscellaneous General Expenses 132,361
10 Directors Fees and Expenses 521,895
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 3,129,106
FERC FORM NO.1 (ED. 12-94)Page 335
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/Q4
(2) FiA Resubmission 04/1612010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Accunt 403,404,4 5)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Accunt 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Accunt 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccunt,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line D~reciation Expense for Asset Limited Term Amortization of
No.Functional Classifcation xpense Retirement Costs Electric Plant Other Electric Total
(Account 403)(Accunt 403.1)(Accunt 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 3,986,275 3,986,275
2 Steam Production Plant 10,392,947 10,392,947
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 7,905,265 7,905,265
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 8,764,880 2,450,031 11,214,911
7 Transmission Plant 9,428,800 9,428,800
"8 Distribution Plant 26,627,445 26,627,445
9 Regional Transmission and Market Operation
10 General Plant 2,737,339 2,737,339
11 Common Plant-Electric 5,252,346 1,031,569 6,283,915
12 TOTAL 71,109,022 5,017,844 2,450,031 78,576,897
B. Basis for Amortization Charges
FERC FORM NO.1 (REV. 12-03)Page 336
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:stimatea Net Appiiea MOrtaliy Average
No.Accunt No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
fal (In Th?~landS)7~l (pefdfnt)(pef;rnt)Trte 7~r
12 STEAM PLANT
13 Colstrip No. 3
14 311 50,467 65.00 -5.00 2.28 S1.5 17.88
15 312 76,183 60.00 -10.00 2.70 R1 18.57
16 314 18,647 50.00 -10.00 3.39 01 28.07
17 315 9,386 55.00 -5.00 2.49 S1.5 20.78
18 316 8,838 50.00 2.26 R2 15.88
19 Subtotal 163,521
20
21 Colstrip NO.4
22 311 49,618 65.00 -5.00 2.35 S1.5 21.32
23 312 49,311 60.00 -10.00 2.83 R1 23.84
24 314 16,284 50.00 -10.00 3.50 01 28.31
25 315 6,706 55.00 -5.00 2.59 S1.5 25.11
26 316 4,212 50.00 2.46 R3 19.98
27 Subtotal 126,131
28
29 Kettle Falls
30 310 148 35.00 2.19 SO
31 311 24,819 65.00 -5.00 2.34 S1.5 20.59
32 312 40,801 60.00 -10.00 3.31 R1 22.43
33 314 13,308 50.00 -10.00 3.18 01 16.35
34 315 10,838 55.00 -5.00 2.74 S1.5 17.61
35 316 2,600 50.00 2.68 R2 21.44
36 Subtotal 92,514
37
38 HYDRO PLANT
39 Cabinet Gorge
40 330 7,725 75.00 2.75 R3 67.57
41 331 10,168 110.00 -5.00 1.62 RO.5 56.19
42 332 31,081 100.00 1.79 R1.5 7796
43 333 37,441 60.00 -5.00 2.59 R1.5 52.14
44 334 5,458 45.00 1.43 R2.5 16.54
45 335 2,615 65.00 0.13 R1 1.20
46 336 1,099 60.00 2.05 S2.5 17.49
47 Subtotal 95,587
48
49 Noxon Rapids
50 330 29,974 75.00 2.83 R3 69.37
FERC FORM NO.1 (REV. 12-03)Page 337
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:stimatea Net Appriea . Mortality l\verage
No.Accunt No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Th~~)sandS)~gr (Pergrnt)(per~nt)TYKe ~~l
12 331 13,151 110.00 -5.00 1.77 RO.5 81.53
13 332 31,974 100.00 1.79 R1.5 75.35
14 333 66,931 60.00 -5.00 2.89 R1.5 56.01
15 334 14,202 45.00 2.53 R2.5 43.88
16 335 3,370 65.00 0.97 R1 19.90
17 336 225 60.00 2.12 R2.5 39.60
18 Subtotal 159,827
19
20 Post Falls
21 330 2,732 75.00 3.79 R3 56.46
22 331 1,297 110.00 -5.00 0.36 RO.5 56.29
23 332 6,044 100.00 2.72 R1.5 92.62
24 333 2,234 60.00 -5.00 0.16 R1.5
25 334 677 45.00 0.14 R2.5 0.01
26 335 223 65.00 2.68 R1 53.83
27 Subtotal 13,207
28
29 Long Lake
30 330 418 75.00 5.68 R3 45.63
31 331 1,847 110.00 -5.00 0.12 RO.5 15.32
32 332 16,638 100.00 1.10 R1.5 24.34
33 333 8,824 60.00 -5.00 1.29 R1.5 13.91
34 334 2,823 45.00 0.82 R2.5 30.46
35 335 529 65.00 1.58 R1 30.46
36 Subtotal 31,079
37
38 Little Falls
39 330 4,217 75.00 7.03 R3 56.31
40 331 1,247 110.00 -5.00 0.12 RO.5 2.00
41 332 5,025 100.00 1.51 R1.5 51.95
42 333 3,964 60.00 -5.00 0.51 R1.5
43 334 2,027 45.00 0.93 R2.5 12.81
44 335 14~65.00 1.18 R1 19.46
45 Subtotal 16,624
46
47 Upper Falls
48 330 64 75.00 2.48 R4 37.64
49 331 582 110.00 -5.00 0.12 RO.5 9.42
50 332 7,126 100.00 1.20 R1.5 76.61
FERC FORM NO.1 (REV. 12-03)Page 337.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/16/2010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:stimateo Net Appiiea MOrtality .
AVerage
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(al (In Th~~~andS)7~r (pe(~nt)(Pe(;rnt)TYKe 7~l
12 333 1,136 60.00 -5.00 0.90 R1.5 6.67
13 334 4,593 45.00 1.85 R2.5 37.00
14 335 107 65.00 2.30 R1 51.46
15 Subtotal 13,608
16
17 Nine Mile
18 330 11 75.00 4.59 R3 34.35
19 331 3,943 110.00 -5.00 2.35 RO.5 80.39
20 332 11,862 100.00 2.16 R1.5 72.53
21 333 9,611 60.00 -5.00 3.03 R1.5 56.34
22 334 2,637 45.00 2.57 R2.5 31.52
23 335 29 65.00 2.31 R1 45.87
24 336 625 60.00 2.64 S2.5 56.50
25 Subtotal 28,986
26
27 Monroe Street
28 331 8,420 110.00 -5.00 1.82 RO.5 109.02
29 332 8,045 100.00 1.72 R1.5 99.22
30 333 11,031 60.00 -5.00 2.28 R1.5 60.23
31 334 1,679 45.00 2.97 R2.5 45.13
32 335 34 65.00 2.04 R1 64.37
33 336 50 60.00 2.17 S2.5 59.42
34 Subtotal 29,259
35
36 OTHER PRODUCTION
37 Northeast Turbine
38 341 365 0.98 sa
39 342 32 55.00 1.31 R3
40 343 9,090 50.00 7.83 S2.5 8.42
41 344 2,605 45.00 0.72 R3
42 345 428 40.00 8.54 S1.5 11.83
43 346 300 1.24 SO
44 Subtotal 12,820
45
46 Rathdrum Turbine
47 341 3,256 3.95 SO
48 342 1,700 55.00 4.10 R2.5 44.14
49 343 3,659 50.00 3.61 S2.5 33.50
50 344 48,858 45.00 3.37 R3 35.49
FERC FORM NO.1 (REV. 12-03)Page 337.2
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:siimatea Net Appiiea Mortality l'verage
No.Accunt No.Plant Base Avg. Service Salvage D~r. rates Curve Remaining
(a)(In Th~~~andS)~~l (per:nt)( er;rnt)TYKe ~~r
12 345 2,552 40.00 3.56 S1.5
13 Subtotal 60,025
14
15 Kettle Falls CT
16 342 89 55.00 4.74 R3 39.59
17 343 9,071 50.00 4.71 S2.5 35.98
18 344 4 45.00 4.98 R3 36.77
19 345 5 40.00 4.48 S1.5 28.3
20 Subtotal 9,169
21
22 Boulder Park
23 341 782 2.63 SO
24 342 116 55.00 2.71 R3 37.93
25 343 57 50.00 3.01 S2.5 40.21
26 344 30,093 45.00 2.84 R3 32.97
27 345 313 40.00 2.97 S1.5 31.24
28 346 7 2.69 SO
29 Subtotal 31,368
30
31 Coyote Springs 2
32 341 11,340 2.76 SO
33 342 19,12 55.00 2.85 R3 44.23
34 344 117,158 45.00 2.92 R3 41.58
35 345 12,696 40.00 3.10 S1.5 32.07
36 346 1,082 2.76 SO
37 Subtotal 161,404
38
39 Solar Power 64
40 Subtotal 64
41 TRANSMISSION PLANT
42 350 16,092 75.00 1.28 R4 53.27
43 352 16,041 60.00 -5.00 1.61 R4 44.73
44 353 177,679 47.00 -15.00 2.39 R3 31.13
45 354 17,113 70.00 -20.00 1.87 S3 43.89
46 355 131,721 60.00 -30.00 1.84 R3 37.27
47 356 106,233 60.00 -10.00 1.93 R3 43.30
48 357 2,605 60.00 1.58 R4 52.84
49 358 2,330 55.00 1.73 S3 41.27
50 359 1,872 65.00 1.65 R4 45.05
FERC FORM NO.1 (REV. 12-03)Page 337.3
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/16/2010
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle t:stimatea Net Appiiea MOrtaliy Average
No.Accunt No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Th~~)sands)7~l (Pergrnt)(pe(;rnt)Tree
7~tr
12 Subtotal 471,686
13
14 DISTRIBUTION PLANT
15 361 14,030 55.00 -10.00 1.80 R3 35.51
16 362 93,198 42.00 -10.00 2.60 R1.5 28.26
17 364 214,303 50.00 -25.00 2.66 R2.5 34.66
18 365 139,009 50.00 -15.00 2.46 R2.5 35.35
19 366 74,816 45.00 -10.00 2.71 R3 36.09
20 367 123,156 28.00 -15.00 6.38 L4 23.05
21 368 169,575 44.00 -5.00 2.00 R2 27.21
22 369 115,182 60.00 -15.00 1.63 R3 38.01
23 370 45,007 38.00 2.39 S1 33.72
24 373 14,931 32.00 -15.00 1.08 R2.5 8.68
25 373.4 14,411 32.00 -5.00 2.82 R2.5 18.79
26 Subtotal 1,017,618
27
28 GENERAL PLANT
29 390.1 3,432 55.00 -5.00 1.85 S2 20.91
30 391.1 1,164 5.00 17.67 sa 3.80
31 393 383 25.00 2.25 So 22.97
32 394 3,455 20.00 4.22 SO 10.35
33 395 1,468 15.00 7.72 sa 7.82
34 397 39,100 15.00 5.40 SO 5.17
35 398 9 10.00 2.37 SO 7.80
36 Subtotal 49,011
37
38 MISCPOWER
39 392 2,589 11.00 10.00 3.70 S3
40 396 2,236 15.00 10.00 5.40 L2
41 Subtotal 4,825
42
43 TOTAL COMPANY 2,588,333
44
45
46
47
48
49
50
FERC FORM NO.1 (REV. 12-03)Page 337.4
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 0411612010
REGULATORY COMMISSION EXPEN ES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a part.
2. Report in columns (b) and (c), only the current yeats expenses that are not deferred and the current yeats amortzation of amounts
deferred in previous years.
Line Description Assessed by Expenses Total . uererrea
No.(Furnish name of regulatory commission or body the Regulatory of Expense for in Account
Current Year 18;2.3 aldocket or case number and a description of the case)Commission Utility (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Federal Energy Regulatory Commission
2 Charges include annual fee and license fees
3 for the Spokane River Project, the Cabinet
4 Gorge Project and the Noxon Rapids Project.2,174,407 200,306 2,374,713
5
6
7
8
9 Washington Utilties and Transportation
10 Commission: includes annual fee and various
11 other electric dockets 849,719 398,791 1,248,510
12
13 Includes annual fee and various other natural
14 gas dockets 437,753 250,746 688,499
15
16 Idaho Public Utilties Commission
17 Includes annual fee and various other electric
18 dockets 366,389 221,758 588,147
19
20 Includes annual fee and various other natural
21 gas dockets 153,853 121,621 275,474
22
23 Public Utilty Commission of Oregon
24 Includes annual fees and various other natural
25 gas dockets 496,247 365,904 862,151
26
27 Not directly assigned electric 788,336 788,336
28 Not directly assigned natural gas 305,338 305,338
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 4,478,368 2,652,800 7,131,168
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
REG JLA TORY COMMISSION EXPENSE~ (Continued)
3.Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accunts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in LineDepartment"'Cfum Amount Accunt 182.3 Accunt Accunt 182.3 No.
(ft
o.
(h)(i)
End ~hYear
(g)(i)(k)(I
1
2
3
Electric 928 2,374,713 4
5
6
7
8
9
10
Electric 928 1,248,510 11
12
13
Gas 928 688,499 14
15
16
17
Electric 928 588,147 18
19
20
Gas 928 275,474 21
22
23
24
Gas 928 862,151 25
26
Electric 928 788,336 27
Gas 928 305,338 28
.29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
7,131,168 46
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612010
DISTRIBUTION OF SALARIES AND AGES
Report below the distribution of total salaries and wages, for the year. Segregate amounts originally charged to clearing accunts to
Utiity Departments, Construction, Plant Removals, and Other Accunts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
a
TotalLine
No.
Classifcation
1 Electric
2 Operation
3 Production
4 Transmission
5 Regional Market
6 Distribution
7 Customer Accounts
8 Customer Service and Informational
9 Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Production
14 Transmission
15 Regional Market
16 Distribution
17 Administrative and General
18 TOTAL Maintenance (Total of lines 13 thru 17)
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
24 Customer Accounts (Transcribe from line 7)
25 Customer Service and Informational (Transcribe from line 8)
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Nat. Gas (Including Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminalin9 and Processing
35 Transmission
36 Distribution
37 Customer Accunts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
4,278,181
6,087,189
302,412
450,051
12,850,633
35,689,074
8,445,939
6,087,189
302,412
450,051
12,850,633
42,853,172
4,140,801
2,657,558
158,315
173,349
4,618,054
12,562,927
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/16/2010
PURCHASES AND SALES OF ANCILLAR SERVICES
Report the amounts for each type of ancilary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancilary services purchased or sold during
the year. Include in a footnote and specify the amount for each type of other ancilary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Biling Determinant Usage - Related Biling Determinant
Unit of Unit of
linE Type of Ancillary Service Number of Units Measure Dollars Number of Units Measure Dollars
No (a)(b)(c)(d)(e)(f)(g)
1 Scheduling, System Contrl and Dispatch 673 MW 136,563
2 Reactive Supply and Voltge
3 Regulation and Frequency Response 231,202 MWh 56,386 73,849 MW 660,210
4 Energy Imbalance 937 MW 3,868,578
5 Operating Reserve - Spinning 36,705 MWh 623,620 83,136 MWh 985,803
6 Operating Reserve - Supplement 65 MWh 1,095 42,975 MWh 578,840
7 Other 1,3$$,B4 MW 12,10MÖ$.......1,353,88 MW ..12,103,405
8 Totl (Unes 1 thru 7)1,622,493 12,921,069 1,554,745 18,196,836
FERC FORM NO.1 (New 2-04)Page 398
Name of Respondent
Avista Corporation
This Report Is:
(1) D An Original
(2) IX A Resubmission
Date of Report
(Mo,Da, Yr)
05/121010
Year/Period of Report
End of 2009/04
COMMON UTILITY PLANT AND EXPENSES
1. Describe the propert carried in the utilty's accunts as common utility plant and show the book cost of such plant at end of year classifed by
accunts as provided by Plant Instructon 13, Common Utility Plant, of the Unifrm System of Accunts. Also show the allocation of such plant costs to
the respective departments using the common utilit plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accmulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accmulated
provisions, and amounts allocated to utilty departents using the Common utilit plant to which such accmulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utilit plant classified by accunts as
provided by the Uniform System of Accunts. Show the allocation of such expenses to the departents using the common utilit plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utilty plant classifcation and reference to order of the Commission or other
authorization.
expenses
911 Sales exense sprvsn 0 0 0 #of cust e yr end
912 Demo and selling expenses 818,688 506,252 312,436 #of cust e yr end
913 Advertising exenses 184,831 114,294 70,537 #of cust e yr end
916 Misc sales expenses 498,015 307,957 190,057 #of cust e yr end
920 Admin & gen salaries 29,027,895 20,977,197 8,050,697 four factor
921 Office supplies &5,245,288 3,781,351 1,463,937 four factor
expenses
922 Adin expenses tranf-0 0 0 four factor
cred
923 Outside srvcs employed 15,344,558 11,054,834 4,289,725 four factor
924 Property insurance 1,498,076 1,079,274 418,802 four factor
925 Injuries and damages 6,252,245 4,670,156 1,582,089 four factor
926 Emloyee pensions &51,299,245 37,077,330 14,221,916 four factor
benefits
927 Franchise requirement 0 0 0 four factor
928 Regulatory commission 1,094,243 788,336 305,906 four factor
expenses
929 Duplicate charges-credit 0 0 0 four factor
930.1 General advertising 341,451 246,582 94,868 four factor
exenses
930.2 Misc general expenses 3,791,176 2,776,920 1,014,256 four factor
931 Rents 442,673 311,267 131,406 four factor
935 Maint of general plant 8,145,748 5,942,208 2,203,540 four factor
403 Depreciation 7,173,935 5,252,346 1,921,588 four factor
404 Amort of LTD term plant 5,532,175 3,986,275 1,545,900 four factor
Note 1: The four factor allocator is made up of 25 percent each of customer counts, direct labor, direct
O&M & Net direct plant
4. Letters of approval received from staffs of State Regulatory Commissions in 1993
FERC FORM NO.1 (ED. 12-87)Page 356.1
Year/Period of ReportThis Report Is:
(1) D An Original
(2) rx A Resubmission
Date of Report
(Mo,Da, Yr)
05/121010
Name of Respondent
Avista Corporation 2009/04End of
COMMON UTILITY PLANT AND EXPENSES
1. Describe the propert carried in the utilty's accunts as common utilty plant and show the book cost of such plant at end of year classified by
accunts as provided by Plant Instructon 13, Common Utilit Plant, of the Unifrm System of Accunts. Also show the allocation of such plant costs to
the respective departents using the common utilty plant and explain the basis of allocation used, giving the allocation factors.
2. Fumish the accmulate provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utiit departents using the Common utilit plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utilit plant classifed by accunts as
provided by the Uniform System of Accunts. Show the allocation of such expenses to the departents using the common utilit plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for lise of the common utilty plant classifcation and reference to order of the Commission or other
authoriation.
1 & 2. Common Plant in service and accumulated provision for depreciation
Acct. No.
303
389
390
391
392
393
394
395
396
397
398
399
Description
Intangible
Land and Land Rights
Structures and Improvements
Office Furniture and Equipment
Transportation Equipment
Stores Equipment
Tools. Shop & Garage Equipment
Laboratory Equipment
Power Operated Equipment
Communications Equipment
Miscellaneous Equipment
Asset Retirement Cost
33,379.076
5,253.922
50.729.510
33,342.183
2.555.865
1,260.275
3.091.076
671.326
2,395.936
20.126.391
501.002
351.680
Total Common Plant
Const. Work in Progress
153.658,240
10.459.887
Total Utility Plant
Acc. Prov. for Dep. & Amort.
164.118.127
43.861.499
Net Utility Plant 120.256.628
3. Comon Exenses allocated to Electric and Gas
Total
departments:
Allocation to
Electric Dept
Allocated to
Gas Dept
Basis of
AllocationAcct. No.Description
901 Cust acctlcollect 1.070,856 567,832 503.024 #of cust i yr end
supervision
902 Meter reading expenses 4.000.093 2,473,536 1,526.557 #of cust i yr end
903 Cust rec & collection 13.649.902 7.462.353 6.187.550 #of cust i yr end
expenses
903.90-99 AIR misc fees 553.481 440,687 112.794 net direct plant
904 Uncollectible accounts 5.159.701 2.735.983 2.423,718 #of cust i yr end
905 Misc cust acct expenses 461,795 244.870 216.925 #of cust i yr end
907 Cust srvc & Info exp 0 0 0 #of cust i yr end
supervision
908 Cust assistance exp 862,408 533.287 329.121 #of cust !9 yr end
909 Info & instruct advert 5.532 2.954 2.578 #of cust i yr end
expenses
910 Misc cust srvc &info 237.087 146.608 90.480 #of cust i yr end
FERC FORM NO.1 (ED. 12-87) Page 356
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612010
DIST IBUTION OF SALARIES AND WAGES (Continued)
YearlPeriod of Report
End of 2009/04
Line Classifcation Total
No.
(a)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru 814,850
56 Transmission (Lines 35 and 47)488,882
57 Distribution (Lines 36 and 48)6,534,084
58 Customer Accounts (Line 37)2,657,558
59 Customer Service and Informational (Line 38)158,315
60 Sales (Line 39)173,349
61 Administrative and General (Lines 40 and 49)4,618,054
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)15,445,092
63 Other Utilty Departments
64 Operation and Maintenance
65 TOTAL All Utilty Dept. (Total of lines 28, 62, and 64)
66 Utiit Plant
67 Construction (By Utilty Departents)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Electric Plant 1,145,306 228,122 1,373,428
74 Gas Plant 72,891 14,518 87,409
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)1,218,197 242,640 .1,460,837
77 Other Accounts (Specify, provide details in footnote):
78 Stores Expense (163)1,672,921 -1,672,921
79 Regulatory Assets (182)7,431 7,431
80 Preliminary Survey (183)29,584 29,584
81 Small Tools Expense (1S4)2,630,995 -2,630,995
82 Miscellaneouse Deferred Debits (186)625,023 625,023
83 Non-Operating Expenses (417)373,256 373,256
84 Expenditures or Certain Civic, Political and Realted Activiti 287,734 287,734
85 Employee Incentive Plane (232380)4,049,397 -4,049,397
86 DSM Tarrif Rider and Payroll Equialization (242600,242700)15,863,599 -14,320,765 1,542,834
87 Incentive 1 Stock Compensation (238000)305,123 305,123
88
89
90
91
92
93
94
95 TOTAL Other Accounts 25,845,063 -22,674,078 3,170,985
96 TOTAL SALARIES AND WAGES 118,073,939 -3,968,459 114,105,480
FERC FORM NO.1 (ED. 12-88)Page 355
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04116/2010
M NTHL Y TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, fumish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for
the definition of each statistical classification.
YearlPeriod of Report
End of 2009/04
NAME OF SYSTEM:
Monthly Peak
MW-Total
Line
No.Month
Hour of
Monthly
Peak
(d)
800
800
800
(a)
1 January
2 February
3 March
4 Total for Quarter 1
5 Apnl
6 May
7 June
8 Total for Quarter 2
9 July
10 August
11 September
12 Tota for Quarter 3
13 October
14 November
15 December
16 Total for Quarter 4
17 Total Year to
Daleear
(b)
: '
21,051
Firm Network Firm Network Long-Term Firm Oter Long- Short-Term Firm Oter
Service for Self Service for Point-ta-point Term Firm Point-topoint Service
Others Reservations Service Reservatin
(e)(f)(g)(h)(i)(j)
1,641 340 151 69 5
1,394 309 151 44 5
1,549 353 151 39 194
4,584 1,002 453 152 204
1,267 233 154 30 79
1,233 228 155 75 259
1,261 244 157 150
3,761 705 466 255 338
1,466 258 157 245 10
1,488 273 156 213 155
1,419 253 156 138 112
4,373 784 469 596 277
1,298 289 155 221 8
1,365 258 154 171 30
1,714 362 15 205 168
4,377 909 463 597 206
17,095 3,00 1,851 694 1,600 1,025
FERC FORM NO. 1/3-0 (NEW. 07-04)Page 400
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/1612010
ELECTRIC ENERGY ACCOUI T
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line Item MegaWatt Hours Line Item MegaWatt Hours
No.No.
(a)(b)(a)(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (Including 8,954,984
3 Steam 1,460,78"Interdepartmental Sales)
4 Nuclear 23 Requirements Sales for Resale (See
5 Hydro-Conventional 3,765,761 instruction 4, page 311.)
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See 4,737,063
7 Other 1,636,701 instruction 4, page 311.)
8 Less Energy for Pumping 25 Energy Furnished Without Charge
9 Net Generation (Enter Total of lines 3 6,863,251 26 Energy Used by the Company (Electric 11,925
through 8)Dept Only, Excluding Station Use)
10 Purchases 7,373,95€27 Total Energy Losses 532,335
11 Power Exchanges:28 TOTAL (Enter Total of Lines 22 Through 14,236,307
12 Received 688,11C 27) (MUST EOUAL LINE 20)
13 Delivered 689,01C
14 Net Exchanges (Line 12 minus line 13)-90C
15 Transmission For Other (Wheeling)
16 Received 3,225,561
17 Delivered 3,225,561
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9,10,14,18 14,236,301
and 19)
FERC FORM NO.1 (ED. 12-90)Page 401a
Name of Respondent This 00rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/16/2010
MONTHLY PEAKS AND OUTPUT
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2. Report in column (b) by month the system's output in Megawatt hours for each month.
3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
4. Report in column (d) by month the system's monthly maximum megawatt load (60 minute integration) associated with the system.
5. Report in column (e) and (f) the specifed information for each monthly peak load reported in column (d).
NAME OF SYSTEM:
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 1,337,102 389,676 1,678 26 0800
30 February 1,209,567 410,926 1,429 10 0800
31 March 1,261,417 426,800 1,585 11 0800
32 April 1,073,235 364,901 1,295 1 1100
33 May 1,176,173 466,079 1,258 29 1600
34 June 1,139,301 433,851 1,296 4 1800
35 July 1,300,754 513,784 1,502 27 1700
36 August 1,144,958 375,374 1,522 3 1700
37 September 1,050,008 350,481 1,451 2 1700
38 October 1,037,430 279,674 1,332 12 0800
39 November 1,192,235 484,229 1,400 30 1800
40 December 1,314,127 241,288 1,763 8 1900
41 TOTAL 14,236,307 4,737,063
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2009/04(2)DA Resubmission 04/1612010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, speciing period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel bumed converted to Mct.7. Ouantities of fuel bumed (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accunts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels bumed.
Line Item Plant Plant
No.Name: CoyoteSpnngs2 Name: Spokane N.E
(a)(b)(c)..
. .........
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Gas Turbine
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Not Applicable Not Applicable
3 Year Originally Constructed 2003 1978
4 Year Last Unit was Installed 2003 1978
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)287.00 56.00
6 Net Peak Demand on Plant - MW (60 minutes)307 40
7 Plant Hours Connected to Load 5950 1
8 Net Continuous Plant Capabilty (Megawatts)278 56
9 When Not Limited by Condenser Water 278 0
10 When Limited by Condenser Water 278 0
11 Average Number of Employees 22 1
12 Net Generation, Exclusive of Plant Use - KWh 1559368000 43000
13 Cost of Plant: Land and Land Rights 0 129664
14 Structures and Improvements 11340586 365280
15 Equipment Costs 150063153 12463105
16 Asset Retirement Costs 351682 0
17 Total Cost 161755421 12958049
18 Cost per KW of Installed Capacity (line 17/5) Including 563.6077 231.3937
19 Production Expenses: Oper, Supv, & Engr 746337 10097
20 Fuel 64261305 3493
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 1729124 2503
26 Misc Steam (or Nuclear) Power Expenses 21027 2581
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 640772 160
30 Maintenance of Structures 0 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 1451442 26842
33 Maintenance of Misc Steam (or Nuclear) Plant 7453 2418
34 Total Production Expenses 68857460 48094
35 Expenses per Net KW 0.0442 1.1185
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
37 Unit (Coal-tonslOil-barreI/Gas-mcf/Nuclear-indicate)MCF MCF
38 Ouantity (Units) of Fuel Burned 10696851 0 0 593 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1020000 0 0 1020000 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 6.007 0.000 0.000 5.891 0.000 0.000
41 Average Cost of Fuel per Unit Bumed 6.007 0.000 0.000 5.891 0.000 0.000
42 Average Cost of Fuel Burned per Milion BTU 5.890 0.000 0.000 5.776 0.000 0.00
43 Average Cost of Fuel Burned per KWh Net Gen 0.041 0.000 0.000 0.081 0.000 0.000
44 Average BTU per KW Net Generation 6997.000 0.000 0.000 14607.000 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2009/Q4(2) DA Resubmission 04/16/2010 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accunts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accunting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name: Kette Falls Name:ep/stri¡f. .Name:Rathdrum No.
(d)(e)(f)
...
Steam Steam Gas Turbine 1
Conventional Conventional Not Applicable 2
1983 1984 1995 3
1983 1985 1995 4
50.70 233.40 166.50 5
50 226 176 6
5198 8528 483 7
50 222 149 8
50 222 0 9
49 222 0 10
30 210 2 11
183407000 1277376000 44308000 12
941300 1289445 621682 13
24818704 100084999 3255691 14
67547018 189567744 56768863 15
450687 134589 0 16
93757709 291076777 60646236 17
1849.2645 1247.1156 364.2417 18
329066 185385 32915 19
8584021 13774324 2627749 20
0 0 0 21
548822 2065287 0 22
0 0 0 23
0 0 0 24
664432 33208 110412 25
385325 2322513 190033 26
0 29773 0 27
0 0 0 28
105236 392967 165 29
40719 505807 1169 30
1502918 3954168 0 31
1112126 1453190 118078 32
200033 737339 38978 33
13472698 25453961 3119499 34
0.0735 0.0199 0.0704 35
Wood Gas Coal Oil Gas 36
Tons MCF Tons Bbls MCF 37
274833 9161 0 803467 1499 0 539630 0 0 38
8500000 1020000 0 17025333 140000 0 1020000 0 0 39
31.064 5.088 0.000 17.003 75.527 0.000 4.870 0.000 0.000 40
31.064 5.088 0.00 17.003 75.527 0.000 4.870 0.000 0.000 41
3.650 4.988 0.000 1.000 12.750 0.000 4.774 0.000 0.000 42
0.047 0.059 0.000 0.011 0.000 0.000 0.059 0.000 0.000 43
12792.000 0.000 0.000 10705.000 0.000 0.000 12423.000 0.000 0.000 44
FERC FORM NO.1 (REV. 12-03)Page 403
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2009/04(2) DA Resubmission 04/1612010 End of
STEAM-ELECTRIC GENERATING PLAT STATISTICS (Large Plants) (Conünued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and intemal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifing period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantit of fuel burned converted to Mct.7. Ouantities of fuel bumed (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accunts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Boulder Park Name:
(a)(b)(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Internal Comb
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Conventional
3 Year Originally Constructed 2002
4 Year Last Unit was Installed 2002
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)24.00 0.00
6 Net Peak Demand on Plant - MW (60 minutes)25 0
7 Plant Hours Connected to Load 1385 0
8 Net Continuous Plant Capabilty (Megawatts),24 0
9 When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 1 0
12 Net Generation, Exclusive of Plant Use - KWh 27763000 0
13 Cost of Plant: Land and Land Rights 144733 0
14 Structures and Improvements 781685 0
15 Equipment Costs 30586720 0
16 Asset Retirement Costs 0 0
17 Total Cost 31513138 0
18 Cost per KW of Installed Capacity (line 17/5) Including 1313.0474 0.0000
19 Production Expenses: Oper, Supv, & Engr 29039 0
20 Fuel 1460673 0
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 158577 0
26 Misc Steam (or Nuclear) Power Expenses 13103 0
27 Rents 104 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 293 0
30 Maintenance of Structures 0 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 243917 0
33 Maintenance of Misc Steam (or Nuclear) Plant 42379 0
34 Total Production Expenses 1948085 0
35 Expenses per Net KW 0.0702 0.000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas
37 Unit (Coal-tonslOil-barreI/Gas-mcf/Nuclear-indicate)MCF
38 Ouantit (Units) of Fuel Burned 259882 0 0 0 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1020000 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 5.621 0.000 0.000 0.000 0.00 0.000
41 Average Cost of Fuel per Unit Burned 5.621 0.000 0.000 0.000 0.00 0.00
42 Average Cost of Fuel Burned per Million BTU 5.510 0.000 0.000 0.000 0.000 0.00
43 Average Cost of Fuel Burned per KWh Net Gen 0.053 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 9548.000 0.00 0.000 0.000 0.000 0.00
FERC FORM NO.1 (REV. 12-03)Page 402.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04(2)DA Resubmission 04/1612010
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Accunt Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam. nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name:Name:Name:No.
(d)(e)(f)
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
0 0 0 8
0 0 0 9
0 0 0 10
0 0 0 11
0 0 0 12
0 0 0 13
0 0 0 14
0 0 0 15
0 0 0 16
0 0 0 17
0.0000 0.0000 0.0000 18
0 0 0 19
0 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.000 35
36
37
0 0 0 0 0 0 0 0 0 38
0 0 0 0 0 0 0 0 0 39
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41
0.000 0.00 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.00 0.000 0.00 0.00 0.000 43
0.000 0.000 0.000 0.000 0.000 0.00 0.000 0.000 0.000 44
FERC FORM NO.1 (REV. 12-03)Page 403.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2009/04
(2)DA Resubmission 04/1612010 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.2545 FERC Licensed Project No.2545
No.Plant Name: Monroe Street Plant Name: Upper Falls
(a)(b)(c)
.....' ... ........,........ ...............
1 Kind of Plant (Run-of-River or Storage)Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Conventional Conventional
3 Year Originally Constructed 1890 1922
4 Year Last Unit was Installed 1992 1922
5 Total installed cap (Gen name plate Rating in MW)14.80 10.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)16 11
7 Plant Hours Connect to Load 8,674 5,840
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions 15 10
10 (b) Under the Most Adverse Oper Conditions 13 10
11 Average Number of Employees 1 1
12 Net Generation, Exclusive of Plant Use - Kwh 103,900,000 51,612,000
13 Cost of Plant
14 Land and Land Rights 0 1,081,854
15 Structures and Improvements 8,20,172 582,599
16 Reservoirs, Dams, and Waterways 8,045,079 7,126,169
17 Equipment Costs 12,743,784 5,835,837
18 Roads, Railroads, and Bridges 50,448 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)29,259,483 14,626,459
21 Cost per KW of Installed Capacity (line 20 I 5)1,976.9921 1,462.6459
22 Production Expenses
23 Operation Supervision and Engineering 2,771 2,769
24 Water for Power 0 0
25 Hydraulic Expenses 0 0
26 Electric Expenses 461,085 484,390
27 Misc Hydraulic Power Generation Expenses 29,151 64,563
28 Rents 0 0
29 Maintenance Supervision and Engineering 0 4,600
30 Maintenance of Structures 2,931 3,746
31 Maintenance of Reservoirs, Dams, and Waterways 24,254 25,608
32 Maintenance of Electric Plant 33,707 48,031
33 Maintenance of Misc Hydraulic Plant 2,599 1,142
34 Total Production Expenses (total 23 thru 33)556,498 634,849
35 Expenses per net KW 0.0054 0.0123
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/16/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, intemal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2058
Plant Name: Cabinet Gorge
d
FERC Licensed Project No. 2058
Plant Name: Noxon Rapids
(e)
FERC Licensed Project No. 2545
Plant Name: Long Lake
Line
No.
Storage
Outdoor
1952
1953
265.00
261
8,748
Storage
Outdoor
1959
1977
480.60
550
6,833
Storage
Conventional
1915
1924
70.00
90
6,900
10,572,310 35,831,527 1,597,959
10,168,310 13,150,391 1,847,066
31,080,974 31,973,870 16,637,951
45,514,034 84,502,791 12,176,179
1,098,564 225,369 0
0 0 0
98,434,192 165,683,948 32,259,155
371.4498 344.7440 460.8451
110,703 89,853 964
43,208 0 0
0 10,924 19,631
1,048,741 1,208,611 650,985
46,621 130,016 76,985
0 0 0
23,844 27,782 2,062
103,585 105,765 55,474
15,447 22,631 85,175
567,474 375,493 206,601
32,353 1,661,857 2,119
1,991,976 3,632,932 1,099,996
0.0019 0.0022 0.0023
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2009/04
(2) DA Resubmission 04/1612010 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available speciing period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No. ...2545 ...FERC Licensed Project No.2545
No.Plant Name: Nine Mile Falls Plant Name: Post Falls
(a)(b)(c)
,...............................
....... ...
1 Kind of Plant (Run-of-River or Storage)Run-of-River Storage
2 Plant Construction type (Conventional or Outdoor)Conventional Conventional
3 Year Originally Constructed 1908 1906
4 Year Last Unit was Installed 1994 1980
5 Total installed cap (Gen name plate Rating in MW)26.40 14.80
6 Net Peak Demand on Plant-Megawatts (60 minutes)21 18
7 Plant Hours Connect to Load 87,334 8,760
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions 18 18
10 (b) Under the Most Adverse Oper Conditions 14 10
11 Average Number of Employees 1 2
12 Net Generation, Exclusive of Plant Use - Kwh 105,851,000 84,350,000
13 Cost of Plant
14 Land and Land Rights 33,429 3,076,554
15 Structures and Improvements 3,943,110 1,297,912
16 Reservoirs, Dams, and Waterways 11,862,323 6,044,594
17 Equipment Costs 12,544,583 3,133,029
18 Roads, Railroads, and Bridges 625,181 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)29,008,626 13,552,089
21 Cost per KW of Installed Capacity (line 20 I 5)1,098.8116 915.6817
22 Production Expenses
23 Operation Supervision and Engineering 2,937 7,062
24 Water for Power 0 0
25 Hydraulic Expenses 12,084 223
26 Electric Expenses 501,116 549,431
27 Misc Hydraulic Power Generation Expenses 51,124 43,688
28 Rents 0 0
29 Maintenance Supervision and Engineering 10,249 664
30 Maintenance of Structures 15,150 91
31 Maintenance of Reservoirs, Dams, and Waterways 153,035 237,537
32 Maintenance of Electric Plant 117,931 206,982
33 Maintenance of Misc Hydraulic Plant 9,086 750
34 Total Production Expenses (total 23 thru 33)872,712 1,046,428
35 Expenses per net KW 0.0082 0.0124
FERC FORM NO.1 (REV. 12-03)Page 406.1
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 0411612010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name: Little Falls
(d)
o FERC Licensed Project No.
Plant Name:
o FERC Licensed Project No.
Plant Name:
o Line
No.
e
Run-of-River
Conventional
1910
1911
32.00
37
6,881
0.00
o
o
0.00
o
o
4,325,371 0 0
1,246,514 0 0
5,025,359 0 0
6,135,097 0 0
0 0 0
0 0 0
16,732,341 0 0
522.8857 0.0000 0.0000
344 0 0
0 0 0
8,948 0 0
565,419 0 0
48,265 0 0
711,664 0 0
1,870 0 0
56,565 0 0
39,972 0 0
168,807 0 0
5,00 0 0
1,606,854 0 0
0.0081 0.000 0.0000
FERC FORM NO.1 (REV. 12-03)Page 407.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2009/04
(2) DA Resubmission 04/1612010 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilit, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.0 FERC Licensed Project No.0
No.Plant Name:Plant Name:
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)0.00 0.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)0 0
7 Plant Hours Connect to Load 0 0
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions 0 0
10 (b) Under the Most Adverse Oper Conditions 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - Kwh 0 0
13 Cost of Plant
14 Land and Land Rights 0 0
15 Structures and Improvements 0 0
16 Reservoirs, Dams, and Waterways 0 0
17 Equipment Costs 0 0
18 Roads, Railroads, and Bridges 0 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)0 0
21 Cost per KW of Installed Capacity (line 20 I 5)0.0000 0.0000
22 Production Expenses
23 Operation Supervision and Engineering 0 0
24 Water for Power 0 0
25 Hydraulic Expenses 0 0
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 0 0
28 Rents 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 0 0
31 Maintenance of Reservoirs, Dams, and Waterways 0 0
32 Maintenance of Electric Plant 0 0
33 Maintenance of Misc Hydraulic Plant 0 0
34 Total Production Expenses (total 23 thru 33)0 0
35 Expenses per net KW 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 406.2
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2009/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04116/2010
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name:
o Line
No.
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
oo
(d (e)
0.00
o
o
0.00
o
o
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0.0000 0.0000 0.0000
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0.0000 0.000 0.0000
0.00
o
o
FERC FORM NO.1 (REV. 12-03)Page 407.2
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
G NERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; intemal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating).2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the fact in a footnote. If licensed project,
give project number in footnote.
Line Year .iristaii~ ca~ac!ty ~et peaK Net Generation
Name of Plant Orig.Name Plate atin Demand Excluding Cost of Plant
No.Const.(In MW)(6~mvn.)Plant Use
(a)(b)(c)(e)(f)
1 Kettle Falls CT 2002 7.20 8.0 5,225,000 9,169,338
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17 i
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38 .
39
40 -
41
42 ,
43
44
45
46
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/16/2010
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro. nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation Production Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc'l. Fuel Filer Maintenance Kind of Fuel (per Millon Btu)No.(g)(h)(i)u)(k)(i)
1,273,519 237,420 303,438 69,559 Nat Gas 502 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
TRANSMISSION LINE STATIST CS
1. Report information conceming transmission lines, cost of Iil'es, and expenses for year. List each transmission line having nominal voltge of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so reuire by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 121, Nonutilty Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line. on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
LE~Gl~ ~gie JPileS)Line \/01 TAr:i=.J~y-Type of(Indicate wtiere u~~ergroun¡r lines NumberNo.other than Of60 cvcle 3 Dhase)Supporting report circuit miles)
un ~tri.eture u~V~~'b1lres CircuitsFromToOperatingDesignedStructureof.Lin~of 1)0 erDesiaraedine(a)(b)(c)(d)(e)(g)(h)
1 Group Sum 60.0C 60.00 1.00
2
3 Group Sum 115.0C 115.00 1,549.00
4
5 Beacon Sub #4 BPA Bell Sub 230.0C 230.00 Steel Tower 1.00 1
6 Beacon Sub BPA Bell Sub 230.0C 230.00 HType 5.00 1
7 Beacon Sub #5 BPA Bell Sub 230.0C 230.00 Steel Pole 4.00 1
8 Beacon Sub #5 BPABellSub 230.0C 230.00 HType 2.00 1
9 Beacon Cabinet Gorge Plant 230.0C 230.00 Stel Tower 1.00 1
10 Beacon Cabinet Gorge Plant 230.0C 230.00 Steel Pole 26.00 2
11 Beacon Cabinet Gorge Plant 230.0C 230.00 HType 53.00 1
12 Beacon Sub Lolo Sub 230.0C 230.00 Steel Tower 1.00 1
13 Beacon Sub Lolo Sub 230.0C 230.00 HType 108.00 1
14 Benewah Shawnee 230.OC 230.00 Steel Pole 60.00 1
15 Noxon Plant Pine Creek Sub 230.OC 230.00 HType 43.00 1
16 Cabinet Gorge Plant Noxon 230.OC 230.00 HType 19.00 1
17 Benewah Sw. Station Pine Creek Sub 230.0C 230.00 Stel Tower 1
18 Benewah Sw. Station Pine Creek Sub 230.0C 230.00 HType 43.00 1
19 Divide Creek Lolo Sub 230.0C 230.00 Steel Tower 1
20 Divide Creek Lolo Sub 230.0C 230.00 HType 43.00 1
21 N. Lewiston Walla Walla 230.0C 230.00 Steel Tower 4.00 1
22 N. Lewiston Walla Walla 230.0C 230.00 HType 43.00 1
23 N. Lewiston Shawnee 230.0 230.00 Steel Tower 7.00 1
24 N. Lewiston Shawnee 230.0 230.00 HType 27.00 1
25 Walla Walla Wanapum 230.0 230.00 Alum.1
26 Walla Walla Wanapum 230.0l 230.00 HType 78.00 1
27 BPA (Libby)Noxon Plant 230.0 230.00 Steel Tower 1.00 1
28 BPAlHot Springs #1 Noxon Plant 23D.l 230.00 Stel Tower 1.00 1
29 BPAlHot Springs #2 Noxon Plant (dead)230.0l 230.00 Steel Tower 2.00 1
30 BPAlHot Springs #2 Noxon Plant .230.01 230.00 HType 68.00 1
31 BPA Line West Side Sub 230.0(230.00 Steel Pole 2.00 2
32 Hatwai N. Lewiston Sub 230.01 230.00 HType 7.00 1
33 Divide Creek Imnaha 230.01 230.00 HType 20.00 1
34 Colstrip Plant Broadview 500.0l 500.00
35
36 TOTAL 2,216.00 3.00 31
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R.eport Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succnct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accunts affected. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (i) on the book cost at end of year.
COST OF LINE (Include in Column 0) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses Expenses
(i)0)(k)(i)(m)(n)(0)(p)No.
136,03f 70,092 206,130 1
2
8,930,84i 92,755,469 101,686,313 441,475 726,272 1,167,741 3
4
95 McMCSR 17,91.1,334,573 1,352,486 327 321 5
1272 McMACSR 6
1272 ACSS 7
1272 ACSS 30,32 3,273,923 3,304,246 1,408 1,4Of 8
95 McMACSR 9
1590 ACSS 10
95 McMACSR 324,321 36,029,040 36,353,367 104,827 104,82/11
95 McMACSR 12
1272 McMAL 456,16 6,761,817 7,217,979 1,202 59,226 60,42f 13
1590 ACSS 570,201 47,541,25(48,111,457 187 97 28.1 14
54 McMAL 105,64 18,015,979 18,121,626 1,508 59,576 61,08.1 15
954 McMAL 49,04!1,076,579 1,125,628 19,149 36,160 55,305 16
54 McMAL 17
~54 McMAL 157,19~2,600,653 2,757,846 3,582 324,270 327,852 18
1272 McMAL 19
1272 McMAL 86,22f 3,692,73C 3,778,958 4,038 177,005 181,04~20
1272 McMAL 21
1272 McMAL 623,984 6,265,206 6,889,190 1,416 9,876 11,292 22
1272 McMAL 23
1272 McMAL 872,151 8,067,073 8,939,224 24
1272 McMAL 25
1272 McMAL 70,781 2,573,418 2,644,199 4,444 4,474 8,91f 26
1272 McMAL 27
1272 McMAL 19,521 19,521 597 7,220 7,811 28
1272 McMAL 29
1272 McMAL 144,63f 3,304,585 3,449,223 156 55,197 55,35"30
1272 McMAL 36,461 594,543 631,004 122 12~31
1272 McMACSR 106,581 2,533,547 2,640,128 285 2,818 3,10 32
1272 McMAL 60,30 1,297,751 1,358,053 33
595,78~28,967,914 29,563,703 236,495 178,667 75,735 490,891 34
35
13,374,618 266,775,663 280,150,281 714,534 1,747,542 75,735 2,537,811 36
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This wort Is:Date of Report YearlPeriod 9f Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/1612010
RANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for concerning Transmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (I) to (0), it is permissible to report in these columns the
Line LINt:IIUN . Line.rURE I:);IUK
No.From To
Lerigth
Type l'werage Present UltimateinNumber perMilesMiles
(a)(b)(c)(d)(e)(f)(g)
1 None added in 2009
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24.
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL
FERC FORM NO.1 (REV. 12-03)Page 424
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2009/04
(2) FiA Resubmission 04/16/2010
TRAN MISSION LINES ADDED DURING Y :;R (Continued)
costS. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
1,,1i::,.t"~T LineVoltageSizeSpecificationConf~uration KV Land and Poles, Towers Conductors Asset Total No.
and -(RaCing (Oper~ting)Land Rights and Fixtures and Devices Retire. Costs(h)(i)(k (I)(m)(n)(0)(p)
115 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2)A Resubmission 04/1612010
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capaciies of Less than 10 MVa except those serving customers with energy for resale, may be grouped accrding
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 STATE OF WASHINGTON
2
3 Airway Heights Distr. Unattended 115.00 13.80
4 Barker Road Distr. Unattended 110.00 13.80
5 Beacon Tmsm. & Distr Unatt 230.00 115.00 13.80
6 Boulder Trnsm. Unattended 230.00 115.00 13.80
7 Chester Distr. Unattended 115.00 13.80
8 Chewelah 115Kv Distr. Unattended 115.00 13.80
9 Colbert Distr. Unattended 115.00 13.80
10 College & Walnut Distr. Unattended 115.00 13.80
11 Colvile 115Kv Distr. Unattended 115.00 13.80
12 Critchfield Distr. Unattended 115.00 13.80
13 Dry Creek Transm. Unattended 230.00 115.00 13.80
14 Dry Gulch Distr. Unattended 115.00 13.80
15 East Colfax Distr. Unattended 115.00 13.80
16 East Farms Distr. Unattended 115.00 13.80
17 Fort Wright Distr. Unattended 115.00 13.80
18 Francis and Cedar Distr. Unattended 115.00 13.80
19 Giford Distr. Unattended 115.00 34.00
20 Glenrose Distr. Unattended 115.00 13.80
21 Greenwood Distr. Unattended 115.00 13.80
22 Hallett & White Distr. Unattended 115.00 13.80
23 Indian Trail Dist. Unattended 115.00 13.80
24 Industrial Park Dist. Unattended 115.00 13.80
25 Kettle Falls Distr. Unattended 115.00 13.80
26 Lee & Reynolds Distr. Unattended 115.00 13.80
27 Libert Lake Distr. Unattended 115.00 13.80
28 Little Falls 115/34Kv Distr~ Unattended 115.00 34.00
29 Lyons & Standard Distr. Unattended 115.00 13.80
30 Mead Distr. Unattended 115.00 13.80
31 Metro Distr. Unattended 115.00 13.80
32 Milan Distr. Unattended 115.00 13.80
33 Millwood Dist. Unattended 115.00 13.80
34 Ninth & Central Distr. Unattended 115.00 13.80
35 Northeast Distr. Unattended 115.00 13.80
36 Northwest Distr. Unattended 115.00 13.80
37 Opportunity Dist. Unattended 115.00 13.80
38 Othello Distr. Unattended 115.00 13.80
39 Post Street Distr. Unattended 115.00 13.80
40 Pound Lane Distr. Unattended 115.00 13.80
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/16/2010
SUBSTATIONS. (Continued)
5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of accunt. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(0)(h)(i)Ii (k)
1
2
24 2 Fred Oil & Air Fan 2 40 3
12 1 Two Stage Fan 1 20 4
536 4 Fred Oil & Air Fan 4 560 5
300 2 Two Stage Fan 2 500 6
24 2 Fred Oil & Air Fan 2 40 7
15 3 8
12 1 Fred Oil & Air Fan 16 20 9
36 2 Two Stage Fan 2 60 10
31 3 Fred Oil & Air Fan 3 45 11
12 1 Two Stage Fan 1 20 12
150 1 Two Stage Fan & Caps 223 250 13
24 2 Fred Oil & Air Fan 2 40 14
12 1 FrOil/Air Fan 1 20 15
12 1 Two Stage Fan 1 20 16
24 2 Fr Oil/Air/2StgFan 2 40 17
36 2 Two Stage Fan 2 60 18
12 1 19
12 1 Fred Oil & Air Fan 1 20 20
12 1 Two Stage Fan 1 2C 21
12 1 Two Stg Fan 1 20 22
12 1 Two Stage Fan 1 20 23
28 3 Two Stg/PtlFred Oil 15 45 24
12 1 Fred Oil & Air Fan 1 20 25
12 1 Two Stage Fan 1 20 26
24 2 Two Stage Fan 2 40 27
12 1 28
36 2 Two Stage Fan 2 60 29
18 1 Two Stage Fan 1 30 30
24 2 Two Stage Fan 2 4C 31
24 2 Fred Oil & Air Fan 2 4C 32
24 2 FrcAir/FrcOillAirFan 2 36 33
24 2 1 Fred & Two Stage Fan 2 40 34
24 2 Two Stage Fan 2 40 35
24 2 Two Stage Fan 2 40 36
12 1 Two Stage Fan 1 20 37
24 2 FrOil/AirFan 2 40 38
36 2 Fred Oil & Wt Fan 2 60 39
24 2 Two Stage Fan 2 40 40
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2) nA Resubmission 04/1612010
SUBSTATIONS
1.Report below the information called for conceming substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped accrding
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Pullman Dist Unattended 115.00 13.80
2 Ross Park Distr. Unattended 115.00 13.80
3 Roxboro Distr. Unattended 115.00 24.00
4 Shawnee Trans. Unattended 230.00 115.00 13.80
5 Silver Lake Distr. Unattended 115.00 13.80
6 Southeast Distr. Unattended 115.00 13.80
7 South Othello Distr. Unattended 115.00 13.80
8 South Pullman Distr. Unattended 115.00 13.80
9 Sunset Distr. Unattended 115.00 13.80
10 Terre View Dist. Unattended 115.00 13.80
11 Third & Hatch Distr. Unattended 115.00 13.80
12 Waikiki Distr. Unattended 115.00 13.80
13 WestSide Trans. Unattended 230.00 115.00 13.80
14 Other: 72substa less than 10MVA Distr. Unattended
15
16 STATE OF IDAHO
17 Appleway Dist. Unattended 115.00 13.80
18 Avondale Dist. Unattended 115.00 13.80
19 Benewah Trans. Unattended 230.00 115.00 13.80
20 Big Creek Distr. Unattended 115.00 13.80
21 Blue Creek Distr. Unattended 115.00 13.80
22 Bunker Hil Limited Distr. Unattended 115.00 13.80
23 Cabinet Gorge (Switchyard)Trans. Unattended 230.00 115.00 13.80
24 Clark Fork Distr. Unattended 115.00 21.80
25 Coeur d'Alene 15th Ave Distr. Unattended 115.00 13.80
26 Cottonwood Distr. Unattended 115.00 24.90
27 Dalton Distr. Unattended 115.00 13.80
28 Grangevile Distr. Unattended 115.00 13.80
29 Holbrook Distr. Unattended 115.00 13.80
30 Huetter Distr. Unattended 115.00 13.80
31 Idaho Road Distr Unattended 115.00 13.80
32 Juliaett Distr. Unattended 115.00 13.80
33 Kamiah Dist. Unattended 115.00 13.80
34 Kooskia Distr. Unattended 115.00 13.80
35 Lolo Tran & Dist Unattnd 230.00 115.00 13.80
36 Moscow Distr. Unattended 115.00 13.80
37 Moscow 230Kv Tran & Dist Unattnd 230.00 115.00 13.80
38 North Moscow Distr. Unattended 115.00 13.80
39 North Lewiston 230kV Trans Unattended 230.00 115.00 13.80
40 North Lewiston Distr. Unattended 115.00 13.80
FERC FORM NO.1 (ED. 12-96)Page 426.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/16/2010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accunts
affected in respondent's books of accunt. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Number of Units Total Capacity No.In Service Transformers (In MVa)
(f)(g)(h)(i)u)(k)
24 2 Fred Oil & Air Fan 2 40 1
30 2 Two Stage Fan 2 60 2
24 2 Two Stage Fan 2 40 3
150 1 Two Stage Fan 250 4
12 1 Frcd Oil & Air Fan 1 20 5
30 2 Two Stage Fan 2 50 6
12 1 Two Stage Fan 1 20 7
30 2 Two Stage Fan 2 50 8
35 4 1 Pt. & Two Stage Fan 52 50 9
12 1 Two Stage Fan 1 20 10
54 3 Two Stg Fan & Cap 103 9C 11
24 2 Two Stage Fan 2 40 12
250 2 13
189 136 .14
15
16
30 2 Two Stage Fan 2 50 17
12 1 Fred Oil & Air Fan 1 2C 18
75 1 Two Stage Fan & Caps 223 125 19
17 2 Portable Fan 2 22 20
20 3 1 21
12 1 Fred Air Fan 1 26 22
75 1 Two Stage Fan 1 125 23..
10 1 ....Fred Air Fan 1 13 24
36 2 Two Stage Fan 2 60 25
12 1 Two Stage Fan 1 20 26
24 2 FrcOil/Air2StgFan ..2 40 27
25 4 FredOillAirlPt Fan 2 34 28
12 1 Two Stage Fan 1 20 29
12 1 Two Stage Fan 1 20 30
12 1 Two Stage Fan 1 20 31
12 1 Fred Oil & Air Fan 1 2C 32
12 1 Two Stage Fan 1 20 33
15 3 Fred Air Fan 2 2C 34
262 3 Fred OillAirlTwo Stg 1 270 35
24 2 FrOil/Air/2Stg Fan 2 40 36
137 2 1 Capacitors 48 37
12 1 Two Stage Fan 1 20 38
250 1 1 Capacitors 48 39
10 3 40
FERC FORM NO.1 (ED. 12-96)Page 427.1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) DA Resubmission 04/1612010
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped accrding
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Oden Distr. Unattended 115.00 21.80
2 Oldtown Distr. Unattended 115.00 21.80
3 Orofino Distr. Unattended 115.00 13.80
4 Osburn Distr. Unattended 115.00 13.80
5 Pine Creek Tran & Dist Unattnd 230.00 115.00 13.80
6 Pleasant View Distr. Unattended 115.00 13.80
7 Plummer Dist Unattended 115.00 13.80
8 Post Falls Distr. Unattended 115.00 13.80
9 Potlatch Distr. Unattended 115.00 13.80
10 Prarie Distr. Unattended 115.00 13.80
11 Priest River Distr. Unattended 115.00 20.80
12 Rathdrum Trans & Distr Unattd 230.00 115.00 13.80
13 Sagle Dist. Unattended 115.00 20.80
14 Sandpoint Distr. Unattended 115.00 20.80
15 South Lewiston Distr. Unattended 115.00 13.80
16 Sweetwater Distr. Unattended 115.00 24.90
17 St. Maries Distr. Unattended 115.00 23.90
18 Tenth & Stewart Distr. Unattended 115.00 13.80
19 Wallace Distr. Unattended 115.00 13.80
20 Other: 28 substa less than 10 MVA Distr. Unattended
21
22 STATE OF MONTANA
23 1 substation less than 10 MVA Distr. Unattended
24
25 SUBSTA. ~ GENERATING PLANTS
26 STATE OF WASHINGTON
27 Boulder Park Trans. Attended 115.00 13.80
28 Kettle Falls Trans. Attended 115.00 13.80
29 Long Lake Trans. Attnded 115.00 4.00 4.00
30 Nine Mile Trans. Attended 115.00 13.80 2.30
31 Little Falls Trans. Attended 115.00 4.00
32 Northeast Trans. Attended 115.00 13.80
33 Post Street Trans. Attended 13.80 4.00 35.00
34
35 STATE OF IDAHO
36 Cabinet Gorge (HED)Trans. Attended 230.00 13.80
37 Post Falls Trans. Attended 115.00 2.30
38 Rathdrum Trans. Attended 115.00 13.80
39 STATE OF MONTANA
40 Noxon Trans. Attended 230.00 13.80
FERC FORM NO.1 (ED. 12-96)Page 426.2
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2) nA Resubmission 04/1612010
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accunts
affected in respondent's books of account. Specify in each case whether lessor, coowner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)0)(k)
10 1 Fred Air Fan 13 1
18 2 Fred Air Fan 2 22 2
20 2 Fred Oil & Air Fan 1 28 3
12 1 Portable Fan 1 15 4
262 3 Capacitors 48 5
12 1 Two Stage Fan 1 20 6
12 1 Two Stage Fan 1 20 7
18 1 Two Stage Fan 1 30 8
15 2 Portable Fan 2 19 9
12 1 Fred Oil & Air Fan 1 20 10
10 1 1 Fred Air Fan 1 13 11
462 3 Fred Oil & Air Fan 49 470 12
12 1 Two Stage Fan 1 20 13
30 3 Fred Air Fan 3 38 14
27 4 Port Fan/FredOiVAil 4 39 15
12 1 Fred Oil & Air Fan 1 20 16
24 2 Two Stage Fan 2 40 17
30 2 Fred Oil/AirlTwo Stg 2 50 18
10 3 19
74 45 1 20
21
22
5 1 23
..24...
25
26
36 1 Two Stage Fan 1 60 27
34 1 1 Two Stage Fan 1 62 28
80 4 1 29
24 2 Fred Oil & Air Fan 1 40 30
24 2 Fred Oil & Air Fan 2 40 31
36 1 Two Stage Fan 1 60 32
2 33
34
35
300 6 1 Fred Oil and Air Fan 2 30 36
16 2 Fred AirlOillAir Fan 2 21 37
114 2 3 Two Stage Fan 2 190 38
39
555 9 1 40
FERC FORM NO.1 (ED. 12-96)Page 427.2
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/04
(2)A Resubmission 0411612010
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped accrding
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize accrding to function the capacities reported for the individual stations in
column (t).
Line VOL TAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1
2 STATE OF OREGON
3 Coyote Springs"Trans. Attended 500.00 13.80 18.00
4
5 SUMMARY:
6 Washington:
7 4 subs Trans. Unattended
8 118subs Distr. Unattended
9 1 subs Tran & Dist Unattnd
10 7 subs Trans. Attended
11 Idaho:
12 3 subs Trans. Unattended
13 63 subs Distr. Unattended
14 4 subs Tran & Dist Unattnd
15 3 subs Trans. Attended
16 Montana:1 sub Trans. Attended
17 1 sub Distr. Unattended
18 Oregon:1 sub Trans. Unattended
19 System: 206 subs
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-96)Page 426.3
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2009/Q4
(2)A Resubmission 04/16/2010
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of accunt. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(0)(h)(i)(j (k)
1
2
213 1 1 Two Stage fan 1 355 3
4
5
6
850 7
1192 8
536 9
269 10
11
400 12
666 13
1123 14
430 15
555 16
5 17
213 18
6239 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-96)Page 427.3
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/16/2010 2009/04
FOOTNOTE DATA
¡Schedule Page: 219 Line No.: 8 Column: c
¡Schedule Page: 219 Line No.: 16 Column: c
Includes: Change in Removal Work in Progress - $179,908
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) 2S An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/16/2010 2009104
FOOTNOTE DATA
!Schedule Page: 227(1) Electric
(2) Gas
'§chedule Page: 227
Footnote Linked.
Line No.: 1 Column: d
Line No.: 5 Column: d
See note on 227, Row: 1, col/item:
¡Schedule Page: 227 Line No.: 7 Column:dFootnote Linked.See note on 227,Row:1,col/item:
¡Schedule Page: 227 Line No.: 8 Column:dFootnote Linked.See note on 227,Row:1,col/item:
¡Schedule Page: 227 Line No.: 9 Column: dFootnote Linked.See note on 227,Row:1,col/item:
¡Schedule Page: 227 Line No.: 10 Column: dFootnote Linked.See note on 227,Row:1,col/item:
ISchedule Page: 227 Line No.: 11 Column: d
Footnote Linked.See note on 227,Row:1,col/item:
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation Î2) A Resubmission 04/16/2010 2009/04
FOOTNOTE DATA
!Schedule Page: 231 Line No.: 22 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 22 Column: dTotal Reimbursements Received Life to Date.
!Schedule Page: 231 Line No.: 23 Column: bTotal Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 24 Column: bTotal Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 25 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 25 Column: d
Total Reimbursements Received Life to Date.
¡Schedule Page: 231 Line No.: 26 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 27 Column: bTotal Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 27 Column: d
Total Reimbursements Received Life to Date.
!Schedule Page: 231 Line No.: 28 Column: b
Total.Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 29 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 30 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 31 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 32 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 33 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 34 Column: b
Total Charges Incurred Life to Date.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Dar Yr)
Avista Corporation (2) A Resubmission 04/16/2010 2009104
FOOTNOTE DATA
!Schedule Page: 310 Line No.: 3 Column: b
SWAP
l$chedule Page: 310 Line No.: 5 Column: b
SWAP
l$chedule Page: 310 Line No.: 7 Column: b
BPA Contract Terminates Septemer 30, 2011.
¡Schedule Page: 310 Line No.: 8 Column: b
BPA Contract Terminates January 1, 2036.
!Schedule Page: 310.1 Line No.: 7 Column: cPondage
l$chedule Page: 310.1 Line No.: 14 Column: cPondage
!Schedule Page: 310.2 Line No.: 7 Column: b
SWAP
l$chedule Page: 310.2 Line No.: 9 Column: b
SWAP
!Schedule Page: 310.2 Line No.: 14 Column: b
SWAP
l$chedule Page: 310.3 Line No.: 2 Column: b
Loss Return
!Schedule Page: 310.3 Line No.: 4 Column: bBundled Transmission
!Schedule Page: 310.3 Line No.: 7 Column: bLoss Return
!Schedule Page: 310.3 Line No.: 9 Column: b
Capacity Contract exires June 30, 2010
l$chedule Page: 310.3 Line No.: 10 Column: b
Bundled Transmission
!Schedule Page: 310.3 Line No.: 12
Capacity Sale expires January
\Schedule Page: 310.3 Line No.: 13
Bundled Transmission
!Schedule Page: 310.3 Line No.: 14 Column: b
Contract terminates January 6, 2011.
¡Schedule Page: 310.4 Line No.: 3 Column: b
NorthWestern Energy LLC sale exires October 31, 2013.
¡Schedule Page: 310.4 Line No.: 9 Column: b
PacifiCorp sale terminates October 31, 2013.
¡Schedule Page: 310.4 Line No.: 10 Column: cPondage
¡Schedule Page: 310.4 Line No.: 11
Peaker, LLC capacity contract
¡Schedule Page: 310.4 Line No.: 12
Contract expires 9/30/2014.
¡Schedule Page: 310.4 Line No.: 13 Column: b
Contract exires 9/30/2014.
¡Schedule Page: 310.5 Line No.: 4 Column: cPondage
¡Schedule Page: 310.5 Line No.: 8 Column: bBundled Transmission
¡Schedule Page: 310.5 Line No.: 11 Column: bPPL sale terminates October 31, 2013.
¡Schedule Page: 310.5 Line No.: 13 Column: b
Puget Sound Energy sale terminates October 31, 2013.
I FERC FORM NO.1 (ED. 12-87) Page 450.1
Column: b
6, 2011.
Column: b
Column: b
terminates Decemer 31, 2016.
Column: b
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 0416/2010 2009/04
FOOTNOTE DATA
!Schedule Page: 310.6 Line No.: 6 Column: b
Contract expires 2014.
!Schedule Page: 310.6 Line No.: 11 Column: b
SWAP
!Schedule Page: 310.7 Line No.: 3 Column: b
Sovereign Power contract terminates 1-31-2010
!Schedule Page: 310.7 Line No.: 4 Column: b
Sovereign Power Contract terminates 1-31-2010
!Schedule Page: 310.7 Line No.: 11 Column: a
Intracompany Wheeling
!Schedule Page: 310.7 Line No.: 11 Column: b
IntraCompany Wheeling terminates 09/30/2023.
!Schedule Page: 310.7 Line No.: 12 Column: a
Intracompany Generation - Sale of Ancillary Services
!Schedule Page: 310.7 Line No.: 12 Column: b
IntraCompany Generation - Sale of Ancillar Services.
!Schedule Page: 310.7 Line No.: 13 Column: b
Estimated revenues - true up in later periods.
I FERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation í2) A Resubmission 04/16/2010 20091Q4
FOOTNOTE DATA
¡Schedule Page: 326 Line No.: 1 Column: a
Fianncial Swap
¡Schedule Page: 326 Line No.: 6 Column: a
Financial Swap
¡Schedule Page: 326 Line No.: 11 Column: a
Non Monetary
¡Schedule Page: 326 Line No.: 13 Column: a
Ancillary Services - Spinning & Supplemental
¡Schedule Page: 326 Line No.: 14 Column: a
Non Monetary
¡Schedule Page: 326.1 Line No.: 11 Column: a
Non Monetary
¡Schedule Page: 326.2 Line No.: 12 Column: a
Financial Swap
¡Schedule Page: 326.3 Line No.: 7 Column: aFinancial Swap
¡Schedule Page: 326.3 Line No.: 8 Column: aNon Monetary
¡Schedule Page: 326.4 Line No.: 4 Column: a
Non Monetary
¡Schedule Page: 326.4 Line No.: 7 Column: aNon Monetary
¡Schedule Page: 326.5 Line No.: 7 Column: a
Financial Swap
¡Schedule Page: 326.6 Line No.: 3 Column: a
Non Monetary
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 04/16/2010 2009/04
FOOTNOTE DATA
ISchedule Page: 332 Line No.: 2 Column: aAncillary Services
¡Schedule Page: 332 Line No.: 4 Column: a
Ancillary Services
¡Schedule Page: 332 Line No.: 5 Column: aUse of Facilities
¡Schedule Page: 332 Line No.: 7 Column: a
Ancillary Services
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/16/2010 2009104
FOOTNOTE DATA
!Schedule Page: 335 Line No.: 6 Column: b
Schedule Page: 335 Line No.: 6
IVendor
VENDORS LESS THAN $5,000
3D INTERNET
ADVENTURES IN ADVERTISING
AMEREN
AZR'S FOOD SERVICES
BANK OF NY - PERSHING
BNYMELLON
BOARDVANTAGE INC
BROADRIDGE
CAREY INTERNATIONAL INC
CITBANK NA
CITY OF SPOKANE
COATES KOKES
CORP CREDIT CARD
CORPORATE EXECUTIVE BOARD
DAVID D HOLMES
DAVIS WRIGHT TREMAINE LLP
DESAUTEL HEGE COMMUNICATIONS
DEWEY & LEBOEUF LLP
EDISON ELECTRIC INSTITUTE
EDS CORPORATION
ENERGY INDUSTRY CBT ALLIANCE
FITCH RATINGS
GARD COMMUNICATIONS
J CRAIG SWEAT PHOTOGRAPHY
MARKTTHIES
MARKET DECISIONS CORPORATION
MELLON INVESTOR SERVICES LLC
MICHAEL G ANDREA
MICHAEL G FOSTER SCHOOL OF BUSINESS
MOODYS INVESTORS SERVICE
NYSE MARKET INC
PAT NEWMANN
PATRICIA J SHEA
R R DONNELLEY RECEIVABLES INC
ROGER D WOODWORTH
SIMANTEL
SUMTOTAL SYSTEMS INC
THE BANK OF NEW YORK MELLON
THE COEUR D ALENE RESORT
THE DAVENPORT HOTEL
THE LAUREL HILL ADVISORY GROUP LLC
VERIFORCE
WASHINGTON STATE UNIVERSITY
WILMINGTON TRUST COMPANY
Purpose
Miscellaneous
Miscellaneous
Professional Services
Treasury Fee
Miscellaneous
Postage
Professional Services
General Services
Employee Car Rental
Miscellaneous
Miscellaneous
Professional Services
Subscriptions
Subscnptions
Offce Supplies
Miscellaneous
Professional Services
General Services
Board Meeting
Miscellaneous
Miscellaneous
Miscellaneous
Professional Services
Miscellaneous
Employee Misc Expenses
Professional Services
Miscellaneous
Employee Misc Expenses
Miscellaneous
Miscellaneous
General Services
Professional Services
Employee Misc Expenses
Rating Agency Fees
Materials & Equipment
Professional Services
Miscellaneous
Miscellaneous
Miscellaneous
Miscellaneous
General Services
Miscellaneous
Miscellaneous
Miscellaneous
Amount I
102,137
3,602
13,408
11,747
11,984
38,896
5,709
20,749
54,372
5,572
36,685
14,286
21,604
46,994
9,069
4,535
3,660
14,357
14,194
5,000
18,613
5,043
30,619
29,230
5,973
22,624
17,874
100,766
6,940
18,011
71,324
36,512
10,606
4,171
6,057
6,448
6,974
4,562
11,837
20,527
21,236
5,326
7,244
8,105
3,602
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04161010 2009/04
FOOTNOTE DATA
!Schedule Page: 335 Line No.: 10
Directors 2009 Expenses
Vendor Name
HEIDI B STANLEY
BRIAN W DUNHAM
MARK RACICOT
ERIK J ANDERSON
KRISTIANNE BLAKE
JOHN F KELLY
MICHAEL L NOEL
R JOHN TAYLOR
JACK W GUSTAVEL
ROYEIGUREN
SCOTT MORRIS
$69,644
$34,167
$9,441
$79,858
$64,528
$75,683
$50,942
$73,353
-$22,544
$71,273
$15,541
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/16/2010 2009104
FOOTNOTE DATA
¡Schedule Page: 398 Line No.: 7 Column: bIn terdepartmen tal spinning reserve service for Native Load.
!Schedule Page: 398 Line No.: 7 Column:dIn terdepartmen tal spinning reserve service for Native Load.
¡Schedule Page: 398 Line No.: 7 Column: eIn terdepartmen tal spinning reserve service for Native Load.
¡Schedule Page: 398 Line No.: 7 Column: gInterdepartmentalspinning reserve service for Native Load.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation i2) A Resubmission 04116/2010 2009104
FOOTNOTE DATA
!Schedule Page: 402 Line No.: -1 Column: b
Operated by Portland General Electric.
I$chedule Page: 402 Line No.: -1 Column: e
Joint project operated by PPL Montana LLC.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)Avista Corporation (2) A Resubmission 04/16/2010 2009104
FOOTNOTE DATA
!Schedule Page: 406 Line No.: -2 Column: b
License period from August 1, 1972 to July 31, 2007. Extended one year 07-09.
¡Schedule Page: 406 Line No.: -2 Column: c
License period from August 1, 1972 to July 31, 2007. Extended one year 07-09.
¡Schedule Page: 406 Line No.: -2 Column: d
License period from March 1, 2001 to February 28, 2046
¡Schedule Page: 406 Line No.: -2 Column: e
License period from March 1, 2001 to February 28, 2046.
¡Schedule Page: 406 Line No.: -2 Column: fLicense period from August 1, 1972 to July 31, 2007. Extended one year 07-09.
¡Schedule Page: 406.1 Line No.: -2 Column: b
License period from August 1, 1972 to July 31, 2007. Extended one year 07-09.
¡Schedule Page: 406.1 Line No.: -2 Column: c
Licensed period from August 1, 1972 to July 31, 2007. Extended one year 07-09.
¡Schedule Page: 406.1 Line No.: -2 Column: dNot a licensed proj ect.
I FERC FORM NO.1 (ED. 12-87) Page 450.1
A-vu-c
A vista Corp.
2009
IDAHO Annual Report
Dr: r"l\~_\J
iow HAY 26 AM 9= 22
REcr=1"" ""'...f.
20 IOHA Y 26 Aff 9: 24
A vista Corp.
2009
IDAHO Electric Report
This Page Intentionally Left Blank
Name of Respondent This Report Is:
(l )~An Original
A vista Corpration (2)DA Resubmission April 16,2010 December 3 i, 2009
Date of Report
(Mo, Da, Yr)
State of Idaho
Year of Report
SUMMAY OF UTILITY PLAN AN ACCUMUATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Line
No.
Item Total Electric
(a)
UTILITY PLANi
2 In Service
3 Plant in Service (Classified)
4 Pro ert Under Ca ital Leases
5 Plant Purchased or Sold
6 Com lete Constrction not Classified
7 Investment in Kettle Falls
8 TOTAL (Enter Total of lines 3 thu 7)
9 Leased to Others
10 Held for Future Use
i 1 Constrction Work in Pro ess
12 Ac uisition Adustments
13 TOTAL Util Plant (Enter Total of lines 8 th 12)
14 Accum. Prov. for De r., Amort., & De 1.
15 Net Util Plant (Enter total of line 13 less 14)
DETAIL OF ACCUMUATED PROVISIONS FOR
DEPRECIATION, AMORTIZATION AN DEPLETION16
17 In Service:
18 De reciation
i 9 Amort. and De 1. of Producin Nat. Gas Lad and Lad Ri hts
20 Accumulated De reciation - Kettle Falls
2 i Amort. of Other Utilt Plant
22 TOTAL in Service (Enter Total of lines 18 th 2 i)
23 Leased to Others
24 De reciation
25 Amortization and De letion
26
27
28
29
30
31
32
33
TOTAL Leased to Others (Enter Total of lines 24 and 25)
Held for Future Use
De reciation
Amortization
TOTAL Held for Futue Use (Ent. Tot. of lines 28 and 29)
Abandonment of Leses (Natual Gas)
Amort. of Plant Ac uisition Ad'ustment
TOTAL Accumulated Provisions (Should agree with line 14 above)
(Enter Total of lines 22, 26, 30, 31, and 32)
908,790,620
499,578
750,833,839
78,643
909,290,198 750,912,482
174,049
3,606,293
o
913,070,540
o
913,070,540
3,225,486
o
754,137,968
o
754,137,968
o o
o o
FERC FORM NO.1 (ED. 12-89)Page 200
A vista Corporation
This R~ort Is:
(l) I! An Original
(2) D A Resubmission April 16, 2010
Date of Report
State of Idaho
Year of ReportName of Respondent
Deember 31, 2009
SUMMAY OF UTILITY PLANT AND ACCUMUATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AN DEPLETION (Continued)
Gas Other (Specify)Other (Specify)Other (Specif)Common Line
No.
1
2
147,715,332 10,241,449 3
420,935 4
5
6
7
148, i 36,267 10,241,449 8
9
174,049 10
341,280 39,527 11
12
10,280,976 13
14
10,280,976 15
o o 33
FERC FORM NO.1 (ED. 12-89)Page 201
Name of Respondent This R~rt Is:Date of Report Yea of Report
2 (1) X An Orgial (Mo, Da, Yr)
A vista Corp.(2)0 A Resubmission April 16, 2010 December 3 i, 2009
ELECTRIC PLA IN SERVICE (Accounts 101,102,103,106)
I. Report below the original cost of electrc plant in service ae-estite basis if necsary, and include the entres in column
cording to the prescribe accounts.(c). Also to be included in colum (c) are entres for reerals
2. In addition to Account 101, Electrc Plant in Service (Clas-of tentative distrbutions of pror year rert in column (b).
sified), this page and the next include Accunts 102, Electrc Plant Ukewise, if the repondent has a signficant amount of plant
Purchased or Sold; Accunt i 03, Experimental Electrc Plant Un-retients which have not ben classified to priry accunts
Classified; and Account i 06, Complete Constiction Not Clas-at the end of the year, include in column (d) a tentative distrib-
sified - Electrc.ution of such retirements on an estited basis, with approp-
3. Include in column (c) or (d), as appropriate, corrections of add- riate contr entr to the account for accumulated depreciation
itions and retirements for the currnt or preding year.prvision. Include also in column (d) reenals of tentative dis-
4. Enclose in parentheses creit adjustments of plant accounts to tnbutions of prior year of unclassified retirements. Attch sup-
indicate the negative effect of such accounts.plemental statement showig the accuiit distrbutions of these
S. Classify Acuntl 06 according to prscrbe accunts, on an tetative classifications in column (c) and (d), including the
Balance at
Line Account Beginning of Year Additions
No.fa)(b)(c)
1 1. INTANGIBLE PLAT
2 301)Or,ianization --
3 302)Franchises and Consents 9,036,684 1,572,741
4 303)Miscellaneous Intani!Ïble Plant -781,818
5 TOTAL Intan,iible Plant (Enter Total oflines 2, 3, and 4)9,036,684 2,354,559
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 310 Lad and Lad Rights --
9 3 11 Strctures and Imorovements --
10 312 Boiler Plant Eauipment --
I I 313 Enl!nes and Enl!ne Driven Genertors --
12 314 Turboiienertor Units --
13 315 Accessory Electric Eauioment --
14 316 Misc. Power Plant Eauipment --
15 317 Asset Retirement Costs for Steam Production --
16 TOTAL Steam Production Plant CEnter Total of lines 8 thru 15)--
17 B. Nuclea Production Plant
18 320 Land and Land Riiihts --
19 321 Strctures and Imorovements --
20 322 Reactor Plant Equipment --
21 323 Turbo,ienertor Units --
22 324 Accessorv Electrc Eauioment --
23 (325 Misc. Power Plant Eauioment --
24 326 Asset Retirement Costs for Nuclear Production --
25 TOTAL Nuclea Production Plant (Ente Total of lines 18 thru 24)--
26 C. Hvdraulic Production Plant
27 330 Land and Land Ri,its 5,953,536 658,508
28 331 Strctures and Improvements 10,889,395 61,428
29 332 Reservoirs, Dams, and Waterays 35,635,193 169,989
30 333 Water Wheels, Turbines, and Generators 39,660,795 17,634
31 334 Accessory Electric Eauioment 6,156,209 22,933
32 335 Misc. Power Plant Equipment 2,588,223 228,299
33 336 Roads, Railroads, and Bridiies 1,098,564 -
34 (337 Asset Retirement Costs for Hvdraulic Production --
35 TOTAL Hydraulic Production Plant(Enter Total oflines 27 th 34)101,981,915 1,158,791
36 D. Other Production Plant
37 340 Land and Land Rights 621,682 -
38 341 Strctures and Imorovements 3,186,951 68,740
39 342 Fuel Holders, Products and Accessories 1,700,144 -
40 343 Prime Movers 3,658,328 -
41 (344 Genertors 48,858,107 -
42 345 Accessorv Electrc Equipment 2,540,221 12,063
FERC FORM NO. t(ED. 12-9t)
State ofldaho
Page 204
State of Idaho
Name of Respondent This ~ort Is:Date of Report Yea of Reprt
(1) X An Original (Mo, Da, Yr)
A vista Corp.(2)0 A Resubmission Apri116,2010 December 31, 2009
ELECTRIC PLANT IN SERVICE (Accounts 101,102,103, and 106) (Continued)
reerals of the prior yea tentative accunt distrbutions of umn (t) only the offset to the debits or credits distrbuted in
these amounts. Careful obseivance of the above intrctions column (t) to priry account classifications.
and the texts of Accounts 10 i and 106 will avoid serous omis-7. For Accunt 399, state the nature and use of plant included
sions of the rert amount of repondents plant actually in the account and if substantial in amount submit a supple-
in seivice at end of year.menta statement showig subaccunt classification of such
6.Show in colum (t) reclassifications or trnsfers within plant confonning to the reuirents of these pages.
utility plant accounts. Include also in colum (t) the additions 8. For each amount comprising the reortd balance ând
or reuctions of priary accunt classifications arising from changes in Accunt 102, state the propert purhased or sold,
distrbution of amounts initially recorded in Account 102. In name of vendor or purchaser, and date of trnsaction. Ifpro-
showing the clearance of Account 102, include in colum (e)posed journal entres have ben fied with the Commission
the amounts with respet to accumulated provision for as reire by the Unifonn System of Accounts,give alsodepreiation, acquistion adjustments, etc., and show in col-date of such filing.
Balance at
Retirements Adjustments Trasfer End of Year Line
(d)(e)(I)(í!)No.
1
---301 2
--10,609,425 302 3
--781,818 303 4
---11,391,243 5
6
7
---310)8
--.311 9
---312)10
---(313)11
---314 12
---(315)13
---316)14
.--317)15
----16
17
----320 18..--321 19
-.--322 20
----323 21
----324 22
----325 23
----326 24
-----25
26
---6,612,04 330)27
15,631 --10,935,192 331)28
---35,805,182 332)29
4,144 --39,674,285 333)30
44,000 --6,135,142 (334)31
---2,816,522 335)32
---1,098,564 336)33
----337)34
63,775 --103,076,931 35
36
---621,682 340 37
---3,255,691 341 38
---1,700,144 342 39
---3,658,328 343 40
---48,858,107 344)41
---2,552,284 (345)42
FERC FORM NO.1 (ED. 12-87)Page 205
Name of Respondent This R~rt Is:Date of Reprt Year of Report
(l) X An Orginal
A vista Corp.(2)0 A Resubmission April 16,2010 December 3 i, 2009
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103, 106)
Balance at
Line Account End of Year Additions
No.(a)(fâ (c)
43 346)Misc. Power Plant Ecuipment .--
44 347)Asset Retirement Costs for Other Production --
45 TOTAL Other Production Plant (Enter Total of lines 37 th 45)60,565,433 80,803
46 TOTAL Production Plant (Enter Total of lines 16, 25. 35, and 45)162,547,348 1,239,594
47 3. TRASMISSION PLAN
48 350 Land and Land Rights 4,723,857 378,307
49 352 Strctures and Improvements 7,878,518 290,423
50 353 Station Equipment 71,663,985 2,872,069
51 354 Towers and Fixtures 556,655 -
52 355 Poles and Fixtures 45,107,749 1,224,502
53 356 Overhead Conductors and Devices 27,858,107 9,462,528
54 357 Underground Conduit --
55 358)Underground Conductors and Devices --
56 (359)Roads and Trails 1,374,002 -
57 1(359.1)Asset Retirement Costs for Transmission Plant --
58 TOTAL Trasmission Plant (Enter Tota of lines 48 th 57)159,162,873 14,227,829
59 4. DISTRIBUTION PLANT
60 (360)Land and Land Rights 964,029 -
61 1(361 Strctures and Improvements 3,220,616 1,238,614
62 (362 Station Ecuipment 29,360,249 3,347,187
63 363 Storage Batterv Ecuipment --
64 364 Poles, Towers, and Fixtures 77,399,457 6,950,855
65 365 Overhea Conductors and Devices 52,931,763 3,707,020
66 366 Underground Conduit 27,500,997 1,127,331
67 367 Underground Conductors and Devices 41,847,168 2,683,411
68 368 Line Transformers 57,285,996 2,101,139
69 (369)Services 42,274,170 1,620,579
70 370)Meters 28,106,354 396,462
71 (371)Installations on Customer Premises --
72 (372 Leaed Propert on Customer Premises --
73 373 Street Lighting and Signal Systems 12,393,941 549,237
74 (374 Asset Retirement Costs for Distrbution Plant --
75 TOTAL Distrbution Plant (Enter Total of lines 60 thru 74)373,284,740 23,721,835
76 5. GENERA PLAN
77 389 Land and Land Rights 101,907 345,425
78 390 Strctures and Improvements 1,125,864 3,729,377
79 (391 Offce Furnitue and Eauipment --
80 392 Transporttion Equipment 1,345,131 1,158,612
81 393 Stores Equipment 14,745 168,326
82 394 Tools, Shop and Garage Eciuipment 432,865 7,522
83 395 Laboratory Ecuioment 130,533 18,511
84 396 Power Operated Equipment 5,753,129 1,419,875
85 397 Communication Eciuipment 3,932,695 1,495,701
86 (398 Miscellaneous Eciuioment 2,299 2,436
87 SUBTOTAL (Enter Tota of lines 77 thru 86)12,839,168 8,345,785
88 399)Other Tangible Proper T --
89 399.1)Asset Retirement Costs for Generl Plant I --
90 TOTAL General Plant (Enter Tota of lines 87 and 90)12,839,168 8,345,785
91 TOTAL (Accounts 101 and 106)716,870,813 49,889,602
92 102)Electrc Plant Purchased --
93 (Ls)(l02) Electric Plant Sold -
94 103)Expermenta Plant Unclassified --
95 TOTAL Electrc Plant in Service 716,870,813 49,889,602
FERC FORM NO.1 (ED. 12-87)
State ofIdaho State of Idaho
Page 206
State of Idaho
Name of Respondent This wort Is:Date of Report Yea of Report
(1) X An Original (Mo, Da, fr)
A vista Corp.(2)D A Resubmission 40284 December 31, 2009
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103, and 106) (Continued)
Balance at
Retirements Adjustments Transfer End of Year Line
(d)(e)(f (,!J No.
----346 43
----(347)44
---60,646,236 45
63,775 --163,723,167 46
47
---5,102,164 (350 48
---8,168,941 352 49
1,281,957 --73,254,097 353 50
---556,655 354)51
58,826 --46,273,425 (355)52
1,055 --37,319,580 356 53
----357)54
----358)55
---1,374,002 359)56
----(359.1)57
1,341,838 --172,048,864 58
59
---964,029 360 60
---4,459,230 361 61
266,222 --32,441,214 362 62
----(363 63
84,817 --84,265,495 364)64
81,638 --56,557,145 (365 65
24,311 --28,604,017 366 66
97,011 --44,433,568 (367 67
17,859 --59,369,276 368 68
33,123 --43,861,626 369)69
---28,502,816 370)70
----371)71
----372)72
41,228 --12,901,950 373)73
----374)74
646,209 --396,360,366 75
.
76
---447,332 389 77
1,290 --4,853,951 390 78
----391 79
726 --2,503,017 392 80
---183,071 393 81
---440,387 394 82
---149,04 395 83
---7,173,004 396)84
9,604 --5,418,792 397)85
---4,735 398)86
11,620 --21,173,333 87
----399 88
----399.1)89
11,620 --21,173,333 90
2,063,442 --764,696,973 91
----102 92
-93
----103)94
2,063,442 --764,696,973 95
FERC FORM NO.1 (ED. 12-87)Page 207
Name of Respondent This R~rt Is:Date of Report Yea of Report
(I) X An Original (Mo, Da, Yr)
A vista Corpration (2)D A Resubmission April 16, 201 0 I Dec. 3 i, 2009
ELECTRC OPERATING REVENU (Account 400)
1. Report below operating revenues for each prescribed for each group of meters added. The average number of
account, and manufactured gas revenues in total.customers means the average of twelve figures at the close
2.Report number of customers, columns (t) and (g), on of each month.
the basis of meters, in addition to the number of flat rate 3. If previous yea (columns (c), (e), and (g), are not
accounts; except that where separate meter readings are derived from previously reported figures, explain any incon-
added for biling purposes, one customer should be counted sistencies in a footnote.
OPERATIG REVENUS
Line Title of Account Amount for Amount for
No.Year Previous Year
(a)~~i Sales of Electricity
2 (440) Residential Sales 101,39~IHl R()~07
3 (442) Commercial and Industrial Sales (3)~14Small (or Commercial)81,073,948
5 Lare:e (or Industrial)62,109,598 56,575,008
6 (44) Public Street and Hiiihway Lighting 2,126,115 1,821,535
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railwavs
9 (448) Interdeoarmental Sales 178,952 142,079
10 TOTAL Sales to Ultimate Consumers 246,886,088 (1)219,340,257
II (447) Sales for Resale 69,738,693 5,676,695
12 TOTAL Sales of Electricitv 316,624,781 225,016,952
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provision for Refunds 316,624,781 ~15 "Other Operatine: Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues 242,635 214,804
18 (453) Sales of Water and Water Power 133,929
19 (454) Rent from Electrc Property 897,391 845,345
20 (455) Interdeoarmental Rents
21 (456) Other Electric Revenues 12,080,448 392,497
22 (456.1) Revenues from Transmission of Electrctv of Others 3,223,695 5,004,067
23
24
25
26 TOTAL Other Operating Revenues 16,578,098 6,456,713
27 TOTAL Electric Ooerating Revenues $333,202,879 $231,473,665
State of Idaho
FERC FORM NO.1 (ED. 12-90)Page 300
Name of Respondent This R~rt Is:
(1) 12 An Original
Date of Report
(Mo. Da, Yr)
State of Idao
Year of Report
A vista Corpration (2) 0 A Resubmission April 16,2010 Dec. 3 i, 2009
ELECTRIC OPERATING REVENUS (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may
be classified according to the basis of classification (Small
or Commercial, and Large or Industral) regularly used by
the respondent if such basis of classifcation is not generally
greater than 1000 K w of demand. (See Account 442 of the
Uniform System of Accounts. Explain basis of classification
in a footnote.)
5. See page 108, Importnt Changes During Year, for
important new territory added and importnt rate increases
or decreases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts
relating to unbiled revenue by accounts.
7. Include unmetered sales. Provide details of such sales
in a foonote.
Amount for Year
Amount for
Previous Year
(e)
A VG. NO. OF CUSTOMERS PER MONT
Number for
Number for Year Previous Yea Line
No.
1
2
3
4
5
6
7
8
9
10
ii
12
13
14
MEGA WATT HOURS SOLD
2,226 2,020 25 23
3,44,692 (2)3,502,520 121,727 120,780
1,664,130 125,471
5,108,822 3,627,991 121,727 120,780
5,108,822 3,627,991 121,727 120,780
(1) Includes $ i ,002,408 of unbiled revenues.
(2) Includes 8,765 MWH relating to unbiled revenues.
(3) Segregation of Commerical and Industrial made on basis of utilzation of energy and not on size of account.
FERC FORM NO.1 (ED. 12-89)Page 301
Name of Respondent This Report Is:
~An Original
Date of Report Year of Report
(Mo, Da, Yr)
A vista Corporation DA Resubmission April 16,2010 Dec. 31, 2009
State of Idaho
SALES OF ELECTRICITY BY RATE SCHEDULES
I. Report below for each rate schedule in effect during the
year the mWh of electrcity sold, revenue, average number of
customers, average kWh per customer, and average revenue
per kWh, excluding data for Sales for Resale which is reported
on pages 310-3 i i.
2. Provide a subheading and total for each prescribed
operating revenue account in the sequence followed in "Elec-
tric Operating Revenues," page 30 I. If the sales under any rate
schedule are classified in more than one revenue account, list
the rate schedule and sales data under each applicable revenue
account subheading.
3. Where the same customers are served under more than
one rate schedule in the same revenue account classification
Line
No.
Number and Title of Rate Schedule MWSold
(a)
i RESIDENTIAL SALES (440)
2 i Residential Service
3 2 Residential Service
4 3 Residential Service
5 i 2 Res. & Farm Gen. Service
6 22 Res. & Farm Lg. Gen. Service
7 30 Pumping-Special
8 32 Res. & Farm Pumping Service
9 48 Res. & Far Area Lighting
10 49 Area Lighting-High-Press.
I i 56 Centralia Credit
12 95 Wind Power
13 73 Residential
14 74 Residential Service
15 76 Residential Service
16 77 Residential Service
17 79 Residential Service
18 58 Tax Adjustment19 Total
20 Residential-Unbiled
21 COMMRCIAL SALES (442)
22 2 General Service
23 3 General Service
24 I I General Service
25 19 Contract-General Service
26 2 I Large General Service
27 25 Extra Lg. Gen. Service
28 28 Contract-Extra Large Service
29 3 I Pumping Service
30 47 Area Lighting-Sod. Yap.
3 I 49 Area Lighting-High-Press.
32 56 Centralia Credit
33 95 Wind Power
34 73 General Service
35 74 Large General Service
36 75 Large General Service
37 76 Large General Service
38 77 General Service
39 79 Area Light-High Press.
40 58 Tax Adjustment41 Total
42 Commercial-Unbiled
43 Total Biled
44 Total Unbiled Rev. (See Instr. 6)45 TOTAL . ..
FERC FORM NO.1 (ED 12.90)
(b)
1,182,333
20,637
12,024
3,685
1,222
281
1,220,182
4,654
(such as a general residential schedule and an off peak water
heating schedule), the entries in column (d) for the special
schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number
of bils rendered during the year divided by the number of
biling periods during the year (12 if all bilings are made
monthly).
5. For any rate schedule having a fuel adjustment clause
state in a footnote the estimated additional revenue biled pur-
suant thereto.
6. Report amount of unbiled revenue as of end of year for
each applicable revenue account subheadinl!.
Average KWH of
Number of Sales per
Customers Customer(d) (e)
Revenue
Revenue
(cents) per
KWH Sold
(f(e)
95,832,303 99,577 11,874 8.1I
2,179,673 4,414 4,675 10.56
863,421 24 501,00 7.18
326,713 594 6,204 8.87
248,995 20.38
72,087 25.65
49,400
1,330,984
100,903,576
493,899
104,609 11,664 8.28
297,718 27,487,095 14,685 20,274 9.23
608,312 45,114,346 1,341 453,626 7.42
69,452 3,665,836 3 23,150,667 5.28
28,085 2,168,390 455 61,725 7.72
972 138,141 14.21
2,383 491,797 20.64
9,693
1,534,147
1,00,922 80,609,445 16,484 61,085 8.02
3,454 464,503
2,227,104 181,513,021 121,093 8.15
8,108 958,402 0 11.82
2,235,212 i 82,47 i ,423 121,093 8.16
Page 304
Name of Respondent This Report Is:
(2An Original
A vista Corporation DA Resubmission
Date of Report Year of Report
(Mo, Da, Yr)
April 16, 2010 Dec. 31, 2009
State of Idaho
SALES OF ELECTRICITY BY RATE SCHEDULES
i. Report below for each rate schedule in effect during the
year the mWh of electricity sold, revenue, average number of
customers, average kWh per customer, and average revenue
per kWh, excluding data for Sales for Resale which is reported
on pages 310-311.
2. Provide a subheading and total for each prescribed
operating revenue account in the sequence followed in "Elec-
tric Operating Revenues," page 301. If the sales under any rate
schedule are classified in more than one revenue account, list
the rate schedule and sales data under each applicable revenue
account subheading.
3. Where the same customers are served under more than
one rate schedule in the same revenue account classification
Line
No.
Number and Title of Rate Schedule MWHSold
(a)
INDUSTRIAL SALES (442)
2 General Service
3 General Service
8 Lg Gen Time of Use
1I General Service
21 Large General Service
25 Extra Lg. Gen. Service
28 Contract-Extra Large Service
29 Contract Lg. Gen. Service
30 Pumping Service -Special
31 Pumping Service
32 Pumping Svc Res & Frm
47 Area Lighting-Sod. Vap.
49 Area Lighting-High-Press.
56 Centralia Credit
72 General Service
73 General Service
74 Large General Service
75 Large General Service
76 Pumping Service
77 General Service
78 Lg Oen Tim of Use
58 Tax Adjustment
Total
Industriål-Unbiled
(b)
i
2
3
4
5
6
7
8
9
10
1I
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27 STREET-AND HWY LIGHTING (44)
28 I1 Generd Service
29 41 CO.-Owned St. Lt. Service
30 42 CO.-Owned St. Lt. Service
31 High-Press. Sod. Vap.
32 43 Cust.-Owned St. Lt. Energy
33 and Maint. Service
34 44 Cust.-Owned St. Lt. Energy
35 and Maint. Svce.-High-
36 Press..Sod. Vap.
37 45 Cust.Owned St. Lt. Energy Service
38 46 Cust.Owned St. Lt. Energy Service
39 High-Press. Sod. Vap.
40 56 Centralia Credit
41 58 Tax Adjustment42 Total
43 Street and Hwy Li~htin~-Unbiled
44 Total Biled
45 Total Unbiled Rev. (See Instr. 6)
46 TOTAL'
3,716
77,924
1,088,882
23,665
3,452
60
51
1,197,750
657
8,847
3,433,701
8,765
3,442,466
FERC FORM NO.1 (ED 12-90)
115
6833
587
280
1,023
Revenue
(c)
366,199
5,601,890
53,953,567
1,803,906
255,831
7,599
9,435
67,165
62,065,592
44,006
17,286
1,884,867
9
85,004
18,158
86,503
33,450
2,126,115
245,704,728
1,002,408
246,707,136
Page 304.1
131
84
8
219
44
486
o
28,366
927,667
136,110,250
108,059
78,455
2,464,506
Revenue
(cents) per
KWH Sold
(f
9.85
7.19
4.95
7.62
7.41
12.67
18.50
5.18
5 23,000 15.03
88 77,648 27.58
i 9,000 9.41
15 39,133 14.48
3 93,333 6.49
II 93,00 8.46
847
121,702
o
121,702
123 71,927 7.20
7.16
11.44
7.17
Name of Respondent This Report Is:
I2An Original
A vista Corporation DA Resubmission April 16,2010 Dec. 31, 2009
State of Idaho
SALES OF ELECTRICITY BY RATE SCHEDULES
Date of Report Year of Report
(Mo. Da, Yr)
i. Report below for each rate schedule in effect during the
year the mWh of electricity sold, revenue, average number of
customers, average kWh per customer, and average revenue
per kWh, excluding data for Sales for Resale which is reported
on pages 310-3 I 1.
2. Provide a subheading and total for each prescribed
operating revenue account in the sequence followed in "Elec-
tric Operating Revenues," page 30 i. If the sales under any rate
schedule are classified in more than one revenue account, list
the rate schedule and sales data under each applicable revenue
account subheading.
3. Where the same customers are served under more than
one rate schedule in the same revenue account classification
Lim
No.
Number and Title of Rate Schedule MWHSold
(a)
OTHER SALES TO PUBLIC
AUTHORITIES (445)
None
(b)
i
2
3
4
5
6
7
8
9
10 SALES FOR RESALE (447) (1)
i i 6 i Sales to Other Utilities - ID
12
13
14
14
15
16
i 7 Note: Sch. 6 i is a state assigned rate schedule for SaleslResale
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39 Total Biled
40 Total Unbiled Rev.
41 TOTAL
INTERDEP ARTNUNTAL
SALES (448)
58 Tax Adjustment
Total 2,226
1,664,130
2,226
(such as a general residential schedule and an off peak water
heating schedule), the entries in column (d) for the special
schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number
of bils rendered dunng the year divided by the number of
biling periods during the year (12 if all bilings are made
monthly).
5. For any rate schedule having a fuel adjustment clause
state in a footnote the estimated additional revenue biled pur-
suant thereto.
6. Report amount of unbilled revenue as of end of year for
each aoolicable revenue account subheading.
A verage KWH of
Number of Sales per
Customers Customer(d) (e)
Revenue
(c)
178,952
178,952
25 89,040
89,040
Revenue
(cents) per
KWH Sold
(f
8.04
8.04
Total 1,664,130 I
FERC FORM NO.1 (ED 12-90)
5,100,057
8,765
5,108,822
25
69,738,693
69,738,693
3 i 5,622,373
1,002,408
3 i 6,624,78 i
Page 304.2
41,898121,727
o
121,727 41,970
6.19
11.44
6.20
Name of Respondent This Report Is:Date of Report Year of Report
I
(1)Ix \AnOriginal
AvistaCo¡.(2)I IA Resubmission April 16. 2010 December 31. 2009
ELECTRIC OPERTION AND MAiNTENCE EXSES
If th amount for previous year is not deried frm previously reportd figures. exlain in footntes.
Une
No.Acunt Amunt for Currnt Year Amun for Pror Year
(a)(b i (c)
1 11 \ POWER PRODUCTION EXNSES
2 A. Steam Por Generation
3 :mration
4 500 i Oiration Suoervision and EnDineerina --
5 501 Fuel --
6 502 Stam ~nênses -.
7 503 Steam frm Oter Sourcs .-
8 Less\ 1504\ Stam Transerrd-e.-.
9 505 Elctrc ExDenses 589 .
10 50 Miscenaneos Steam Power Exoenses 26653 29469
11 507 Rents --
12 509 Allowances --
13 TOTAL Onêralin 1 Ener Total of Unes 4lhru 11\27242 29469
14 Maintnence
15 510 Maintenance SUnêrvision and~nerina 68 2695
16 511 Maintnanc of Strres --
17 512 Maintenance of Boiler Plant .-
18 513 Mainnance of Electc Plant -.
19 514 Maintenanc of Miscenaneous Stam Plant --
20 TOTAL Maintenanc 1 Enter Total of Unes 14lhru 18\680 2695
21 TOTAL Power Proucton Eitnses-Stam Plant (Enter Total ofnnes 12 and 19\27922 32165
22 B. Nudear Power Generation
23 Ooeratin
24 517 i Oiratlon Suiirvislon and Enalneerina --
25 518 Fuel --
26 519 Colants and Water -.
27 520 Steam Eitnses --
28 521 Stam frm Otr Sourcs --
29 Less\ 1522\ Stam TransferrCr.--
30 523\Elec Exenses --
31 524\Misnaneous Nudear Power Eises --
32 525\Rents .-
33 TOTAL Onratin IEnterTotal of riens 23lhru 31\--
34 Maintnanc
35 528 Mainnanc Si.rvsion and Enalneerina --
36 529 Maintenance of Strctres --
37 530 Maintenance of Reactr Plant Eauioment --
38 531 Mainnance of El Plant --
39 532 Maintenanc of Miscenaneus Nuclear Plant -.
40 TOTAL Maintnanc IEnterTotal of lines 34lhru 38).-
41 TOTAL Por Prducton i:Ynnses-Nuclear PowrlEntertotal of lines 32 and 39\--
42 C. HVraulic Powr Generation
43 )aeratin
44 535I Oiratlon Suoervision and EnDineerina 79830 576382
45 536 Wate fo Por 286362 26999
46 537 Hvdraulic Exnses 1867708 966417
47 538 Elec Einses 164 377 1381772
48 539 MiscilneousHvraulic Powr Generation Exenses 167116 369.894
49 54 Rent 2145975 11556
.50 TOTAL Ooeratin IEnter Total of lines 43lhru 48\6910838 3675024
:; 1
FERC FORM NO.1 (12-96)Page 320
Ido 3/16110 For 1 Pl 320_20.i
¡ame of Respondent This Report Is:Date of Report Year of Report
I
(1)Ix IAn Original
Avista Cor.(2)I IA Resubmlsion Apn116, 2010 Dembe 31. 2009
ELECTIC OPERATION AND MAINTENCE EXENSES
Line
No.Acunt Amount for Currnt Year Amnt for Previous Year
fa J fbI fc J
50 C. HYdraulic Power Generetion (Contnued)
51 Maintenance
52 541 Maintenance Suoervslon and Enoineerina 87034 59208
53 542 Maintenance of Strctres 103726 92885
54 543 Maintenance of Reservirs Dams and Waterways 267952 104072
55 544 Maintenance of Electc Plant 84660 407029
56 54 Maintnance of Miscellaneous HYdraulic Plant 75554 128007
57 TOTAL Maintenanc (Enter Total of lines 52 thru 56\1382925 791201
58 TOTAL Power Pructin Exnses-Hvdraulic Poer (Enter tol of lines 49 and 57\8293763 446225
59 D. Oter Power Generation
60 Orieration
61 54\ ODration Su-rvslon and Enoineerino 38150 187627
õ2 547 Fuel 2627749 1332065
63 54 Generation Exnses 110412 143 951
64 54 Miscellaneous Oter Power Generation Exrienses 267663 20864
65 550 Rent (11914 (12.034
66 TOTAL ODratin (Enr Total of lines 61 thru 65)3032060 1860 251
67 Maintenance
68 551 Maintnance Suoervslon and Ennineerina 41886 54201
69 552 Maintenanc of Strctres 1169 1492
70 553 Maintenance of Generatina and Elec Plant 118078 139334
71 554 Maintenanc of Miscellaneous Oter Poer Generation Plant 42205 59690
72 TOTAL Maintnance (Enter Total of lines 68lhru 711 203338 254717
73 TOTAL Power Pruction i:""nses-or Power (Enter Total of lines 66 and 72\3235398 2114968
74 E. Oter Power Sunnlv Fynenses
75 555) Purchased Powr 106719593 98.54379
76 556) SYSm Contrl and load Diiinatchinn 185723 178249n55) Otr Emnses 1254494 21009194
78 TOTAL OIr Por SUDrilv Emenses (Enter Total of lines 75 thru n\11944809 119691.822
79 TOTAL Por Prucon !=YDênsS Enr Total of lines 20 40.58 73 and 78\131005893 126305180
80 2. TRSMISSION EXENSES
81 )iratin
82 56) Oiiration SunAslon and Ennineerina 852402 790512
83 561) load DisDatca 769280 694403
84 561.1 load Disriatchlna Reliabillt --
85 561.2 load Disriatclna Monitr and ODrate Transmission SYSem --
86 561.3 load Disriathlno Transmission Serv and Schee --
87 561.4 Scheculin.. Svsemt Contl and DisDatc Servces --
88 561.5 ReliabDi P1annirir. and Stndards DeveloDment --
89 561.6 Transmission Servce Stulfies --
90 561.7 Generation Inrcnnen Studies --
91 561.8 Rellabillv. P1annin" and Standards DeveloDment Servs --
.92 562 Station I=oenses 69316 80512
93 563 Overhad Line I=ses 79442 201791
94 56 Undemround Line FYfnses --
95 565 Transmission of Elect"ii bv Oter 4690115 485026
96 56 Miscllaneus TransmissionEmnses 48 611 4645
97 567 Rents 26811 11325
98 TOTAL ODratin (Enr Total of lines 82 thru 89)6971978 7095265
99 Maintenanc
100 56 Mainnance Su..rvsion and Enoineerina 166195 155286
101 569 Mainnanc of Stres 120137 132710
102 570 Maintnanc of Sttion EOuTiment 416494 385.303
103 571 Maintenance of Ovmead Lines 1005428 48336
104 572 Maintnance of UndAmround Lines 3892 -
105 573 Maintenance of Miscellaneous Transmission Plnt 16288 4893
106 TOTAL Maintnance (Enter Total of lines 92 th 97\172843 1161555
107 TOTAL Transmission-"'''Mnses (Ente Total of lines 90 and 98\8 700413 825821
108 3. DISTRIBUTIO EXENSES
109 Ooeration
110 580\ Ooeration Suiision and Enolneerina 48527 45876
'ERC FORM NO.1 (12-96)Page 321
Idaho 3116110 For 1 pg 3223_209.i
Name of Respondent This Repor Is:Date of Report Year of Report
I
(1)Ix IAn Original
Avista CoC.(2) I IA Resubmission April 16. 2010 Decembr 31, 209
ELECTRIC OPERTION AND MAINTENACE EXPENSES
Lie
No.Acunt Amount for Currnt Year Amount for Prior Year
(a)(b)(c i
103 3. DISTRIBUTION EXPENSES tContinued\
104 581 Load Disnatchin"--
105 582 Sttion Exenses 218337 244290
106 583 Ovrhad Une Exoenses 54930 657028
107 584 Underaround Line Exnses 252091 288975
108 585 Stt Liahtna and Sicnal System Emnses 172955 153838
109 586 Meter Exnses 139228 6837
110 587 Custmer Installatins Exnenses 40185 44342
111 588 Miscellaneous Distrbuton Exnenses 1780724 1542106
112 589 Rent 89562 62715
113 TOTAL Ooeration tEntr Total of lines 102 thru 112\4088.203 3859008
114 Maintenanc
115 590 Maintenance Suoervsion and Enaineerina 461.079 447419
116 591 Maintnance of Strctres 103495 61480
117 592 Maintenanc of Statin !=l'uinment 365933 158009
118 593 Maintenance of Overhead Unes 2618661 3123 891
119 594 Maintnance of Underaround Lines 28654 31146
120 595 Maintnanc of Line Transformrs 261020 108403
121 596 Maintenance of Street Lil'htina and Sianal Systems 19043 14240
122 597 Maintenance of Meters 3833 45.544
123 598 Maintenanc of Miscellaneous Distrbuon Plant 79238 210123
124 TOTAL Maintenance fEnTotal of lines 115 thru 123\4404741 4608.726
125 TOTAL Distrbuton Exnses (Enter Total of lines 113 and 124\849294 8467734
126 4. CUSTOMER ACCOUNTS EXPENSES
127 Ooeration
128 901 Suoervsion 194693 168326
129 902 Meter Redina Exnenses 362283 292217
130 903 Custor Records and Collection ElCnses 2709234 2513513
131 904 UncoHecble Acunts 938087 661036
132 905 Miscllaneous Customer Acunts EXi:nseS'83959 5056
133 TOTAL Customer Acunts Exnses Tenter Total of lines 128 thru 132\4288.255 368659
134 5. CUSTOMER SERVE AND INFORMTIONA EXPENSES
135 )nration
136 907 Suoervsion .-
137 908 Customer Assistnce Exnenses 5867133 3.881823
138 909 ~nnatinal and Insùctonal Exnenses 17264 32428
139 910 Miscllaneous Custmer Service and Inonnatlonal Exoenses 50267 49825
140 TOTAL Cusl Servce and ~nntlonal Exnenses tEner Total of lines 136 thru 139\5934.664 396076
141 6. SALS EXENSES
142 )nration
143 911 Suoervision --
144 912 Demostrtlna and SeHinl' Exoenses 173500 155244
145 913 Advertsina Exoenses 39188 40564
146 916 Miscellaneous Sales Exiinses 38600 21
147 TOTAL Sales Exnses (Enter Total of lines 143 thru 146\251288 195829
148 7. ADINISTRTIV AND GENER EXNSES
149 Oiiration
150 920\ Administrti and General Salaries 8148288 6574227
151 921) Ofce SUDDlies and Exnenses 1379591 1297351
152 Less) (922) Administive exiinses Transferrd-eredit (17 312 (13.32
FERC FORM NO.1 (12-96)Page 322
Idao 3116110 For 1 pg 32023-.D0.x
lame of Respondent This Report Is:Date of Report Year of Report
I
(1)Ix IAn Orginal
AvistaCor'(2)I IA Resubmission Apnl 16. 2010 Decebe 31, 2009
aeCTRIC OPETIO AND MACE EXENSES
Une
No.Acunt Amount for Currnt Year Amunt for Pnor Year(al fbI (c I
153 7. ADMINISTRTIV AND GENERA EXENSES (Continued\
154 923 Ouide Servces Emnloved 3972670 3772598
155 924 pronert Insurance 45607 34 360
156 925 Inlunes and Dama"es 1243326 1 023022
157 926 EmDlvee Pensions and Benefts 338 615 377 208
158 927 Francse Reauirements 6704 5950
159 928 teulatorv Commission Exnses 1698820 1763403
160 less 929\ Duolicate Chan:es-.-.
161 930.1 General Advertsin" Einses 84243 .
162 930.2 Miscellaneous General Exenses 1019353 1030973
163 931\ Rents 100527 174907
164 TOTAl Ooratin Center Total of lines 150 thru 163\18425432 16354678
165 Maintenance
166 935\ Maintenanc of General Plant 2102635 1896567
167 TOTAl Administrtie and General Einses (Enter Total of lines 164 and 166\20528067 18251244
,168 TOTAl Becc Oneration and Maintenance Exnenses (Enter Total of lines 179201524 169126543
7999.125133140 147 and 167\
NUMBER OF aECTRIC DEPARTMENT EMPlOYEES I
1. The data on numbe of employes should be reportd constrcton employe in a footnote.
)r!h payrll penod ending nearest to Ocber 31. or any 3. The number of employes assignable to the elecl
ayrll penod ending 60 days before or aftr Ocber 31.departnt frm joint funcons of cobination utlities may
2. If th respondenls payrll for th reportng penod in-be determined by estimate, on the basis of employee equiva-
ludes any speal constctn persnne, include such Ients. Sho the estimated number of equivalent employees
mployees on 6ne 3, and show the number of such speial attbuted to the elecc departent frm joint functions.
1 Pavrll Penod Ended (Date\ Dember 31 2009
2 Total Reaular Full-Time Emoloves 83 87
3 Tota Part-Time and TemDOrarv ErDIOvs 2 4
4 Alcation of General EmDloves 128 122
5 Totl Emoloves (Se Note 1\213 213
':
ERC FORM NO.1 (12-96)Page 323
=Ida 3116110 For 1 P9 3223_209.i